HOUSTON, May 02, 2018 (GLOBE NEWSWIRE) -- Marathon Oil Corporation (NYSE:MRO) today reported first quarter 2018 net income of $356 million, or $0.42 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. Adjusted net income was $154 million, or $0.18 per diluted share. Net operating cash flow was $649 million, or $707 million before changes in working capital.
Highlights
- Total production averaged 398,000 net boed, excluding Libya; U.S. production averaged 284,000 net boed and U.S. oil production averaged 164,000 bopd, both up 9% sequentially on a divestiture-adjusted basis
- Eagle Ford maintained flat production of 104,000 net boed; 11 wells in Atascosa County had average 30-day IP rates of 1,615 boed (76% oil)
- Bakken production increased to 74,000 net boed, up 7% sequentially; Arkin well in Hector set new basin Three Forks record with 3,040 bopd 30-day IP; June and Chauncey wells in West Myrmidon set new basin Middle Bakken records with 3,470 bopd average 30-day IP rates
- Oklahoma production up 17% sequentially to 75,000 net boed; oil production up 25% sequentially; STACK leasehold drilling largely completed in first quarter
- Northern Delaware production increased to 16,000 net boed; seven wells across Eddy and Lea Counties had average 30-day IP rates of 1,460 boed (69% oil)
- Captured more than 250,000 net acres in multiple new plays in the last year, including a largely contiguous position in the emerging Louisiana Austin Chalk play at a cost of less than $900 per acre
- Received $1.2 billion in proceeds from the Libya sale and the final Canadian oil sands payment
- Raised 2018 annual resource play oil and boe production guidance to 25 - 30%, up from 20 - 25% previously, while maintaining the $2.3 billion 2018 development capital budget
"Our returns-focused investment program coupled with outstanding execution across our multi-basin portfolio drove production above the top end of our U.S. guidance in the first quarter. Continued strong performance in Bakken and Eagle Ford delivered significant free cash flow while enhancing inventory value in both the Hector area and Atascosa County. Delineation and appraisal activity continued in the Northern Delaware and Oklahoma as we transition to multi-well pad drilling in both assets," said Marathon Oil president and CEO Lee Tillman. "Critical to our long-term value creation and full-cycle returns, we captured future potential opportunities through low-cost exploration acreage additions, including a material position in the emerging Louisiana Austin Chalk play.
"Marathon Oil remains committed to financial discipline, and while we're increasing full year resource play guidance, our 2018 development capital budget is unchanged. We're on track to deliver a strong rate of change in our key performance metrics, including an annual increase of over 65 percent in corporate-level cash returns at current strip prices," he said.
Capital
First quarter development capital expenditures, before working capital, were $618 million, and are not ratable for the balance of 2018 due to higher working interest and non-operated pace relative to the remainder of the year. Net cash provided by continuing operations was $649 million during first quarter 2018, or $707 million before changes in working capital. The Company's 2018 development capital budget is still anticipated to be $2.3 billion.
Outside of the development capital budget, resource play leasing and exploration (REx) capital expenditures were $94 million in the first quarter, more than fully funded through divestiture proceeds. Though episodic in nature, the Company expects second quarter REx capital expenditures to be approximately $150 million.
Production Guidance
Marathon Oil expects second quarter 2018 U.S. production to average 280,000 to 290,000 net barrels of oil equivalent per day (boed). Within this guidance, the Company expects second quarter 2018 U.S. resource play production to average 270,000 to 280,000 net boed. Second quarter 2018 International production is expected to average 115,000 to 125,000 net boed.
For full-year 2018, the Company now expects annual resource play oil and barrel of oil equivalent (boe) growth of 25 - 30 percent, up from 20 - 25 percent previously, and is trending toward the high end of its 2018 guidance ranges for total Company oil and boe.
U.S. E&P
U.S. E&P production averaged 284,000 net boed for first quarter 2018, up 9 percent compared to the prior quarter and up 39 percent from the year-ago quarter on a divestiture-adjusted basis. First quarter production from the U.S. resource plays was 269,000 net boed, up from 249,000 net boed in the prior quarter. First quarter U.S. E&P unit production costs were $5.89 per boe and are expected to moderate through 2018 as the Company implements its plans to access additional infrastructure.
EAGLE FORD: Marathon Oil's Eagle Ford production averaged 104,000 net boed in the first quarter, compared to 105,000 net boed in the prior quarter. The Company brought 34 gross Company-operated wells to sales with average 30-day initial production (IP) rates of 1,750 boed (64% oil). Enhanced completion designs continued to deliver solid results outside of core Karnes County, where the four-well Carpenter Kellner pad and the four-well Guajillo West pad achieved average 30-day IP rates of 1,690 boed (78% oil) and 1,635 boed (73% oil), respectively. The Eagle Ford asset generated significant free cash flow in the quarter through a combination of well performance and oil realizations that averaged $1.50 above WTI due to strong LLS-based pricing.
BAKKEN: In first quarter 2018, Marathon Oil's Bakken production averaged 74,000 net boed, up 7 percent compared to 69,000 net boed in the prior quarter. The Company brought 11 gross Company-operated wells to sales, six of which were in core Hector with average 30-day IP rates of 2,600 boed (81% oil). The Arkin well in Hector set a new Williston Basin Three Forks record delivering a 30-day IP oil rate of 3,040 barrels of oil per day (bopd). The Company set two new basin Middle Bakken records in West Myrmidon with average 30-day IP rates of 3,470 bopd from the June and Chauncey wells. Two additional West Myrmidon wells that came online late in the quarter, the Mark Middle Bakken well and Wilbur Three Forks well, achieved 24-hour IP rates of 10,875 boed and 7,570 boed, respectively, and are not yet at 30 days of production. The Company continues to optimize completion designs to improve well productivity, increase capital efficiency and reduce costs while generating substantial free cash flow.
OKLAHOMA: Marathon Oil's Oklahoma production averaged 75,000 net boed during first quarter 2018, up 17 percent from 64,000 net boed in the prior quarter. Oil production was up 25 percent sequentially, primarily as a result of strong carry-in performance from the nine-well Tan infill that came online late in the fourth quarter. The Company brought 17 gross operated wells to sales primarily focused on Meramec leasehold activity in the STACK. This largely completes the STACK leasehold program for the year, and allows for the transition to pad drilling for the remainder of 2018. In the normally pressured STACK, improved drilling efficiencies and optimized completion designs resulted in completed well costs for first quarter standard-lateral Meramec wells averaging $4 million.
NORTHERN DELAWARE: Marathon Oil's Northern Delaware production averaged 16,000 net boed in first quarter 2018, up from 11,000 net boed in the prior quarter. The Company brought nine gross Company-operated wells to sales across the Malaga, Red Hills and Ranger areas in Eddy and Lea Counties, seven of which had average 30-day IP rates of 1,460 boed (69% oil). Two wells from the Cypress infill pilot came to sales ahead of schedule in the last week of the quarter. A two-well 3rd Bone Spring / Upper Wolfcamp pad in Red Hills achieved average 30-day IP rates of 1,830 boed (68% oil), and an Upper Wolfcamp well in Malaga had an average 30-day IP rate of 2,095 boed (69% oil). In the last six months, Marathon Oil has added 165 risked gross Company-operated locations with an average working interest of 65 percent through trades and a small bolt-on acquisition. The Company is currently benefiting from its Midland-Cushing basis swaps. Open positions include 10,000 bopd hedged at a discount of less than $1 to WTI for the second half of 2018 and all of 2019.
International E&P
International E&P production, excluding Libya, averaged 114,000 net boed for first quarter 2018, compared to 121,000 net boed in the prior quarter. The decrease reflects planned turnaround activity in EG that was completed in the quarter. First quarter 2018 International E&P unit production costs (excluding Libya) averaged $5.37 per boe, up sequentially due to the timing of liftings in the U.K. and international production mix.
Corporate
Total liquidity as of March 31 was approximately $5 billion, which consisted of $1.6 billion in cash and cash equivalents and an undrawn revolving credit facility of $3.4 billion. On March 1, the Company closed on the sale of its Libya subsidiary for $450 million and proceeds were received on the same day. Additionally, the final Canadian oil sands payment of $750 million was received.
For the remainder of 2018, the Company's open hedge positions include an average of 98,000 bopd at a weighted average floor price of $52.18 and a weighted average ceiling price of $57.11, hedged through a combination of three-way collars and fixed price swaps, as of April 27.
The adjustments to net income from continuing operations for first quarter 2018 totaled $202 million before tax, primarily due to a $257 million gain from sale of the Libya subsidiary, partially offset by an unrealized loss of $43 million on commodity derivatives.
A slide deck and Quarterly Investor Packet will be posted to the Company's website following this release today, May 2. On Thursday, May 3, at 9:00 a.m. ET, the Company will conduct a question and answer webcast/call, which will include forward-looking information. The live webcast, replay and all related materials will be available at https://www.marathonoil.com/Investors.
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), net cash provided by operations before changes in working capital, net cash provided by operations before changes in working capital and the U.K. tax payment, and corporate-level cash returns 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 and net cash provided by operations before changes in working capital and the U.K. tax payment 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 of adjusted net income (loss) and net cash provided by operations before changes in working capital and its most directly comparable GAAP financial measure. A reconciliation to their most directly comparable GAAP financial measures can be found in our investor package on our website at www.marathonoil.com. 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 2018 capital budget and allocations, future performance, free cash flow, corporate-level cash returns on invested capital, business strategy, asset quality, drilling plans, production guidance, cash margins, asset sales and acquisitions, leasing and exploration activities, production, 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, 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 2017 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 Contacts:
Zach Dailey: 713-296-4140
John Reid: 713-296-4380
| Consolidated Statements of Income (Unaudited) | Three Months Ended | ||||||||
| Mar. 31 | Dec. 31 | Mar. 31 | |||||||
| (In millions, except per share data) | 2018 | 2017 | 2017 | ||||||
| Revenues and other income: | |||||||||
| Revenues from contracts with customers | $ | 1,537 | $ | 1,336 | $ | 873 | |||
| Net gain (loss) on commodity derivatives | (102 | ) | (151 | ) | 81 | ||||
| Marketing revenues | — | 45 | 34 | ||||||
| Income from equity method investments | 37 | 73 | 69 | ||||||
| Net gain (loss) on disposal of assets | 257 | 32 | 1 | ||||||
| Other income | 4 | 47 | 14 | ||||||
| Total revenues and other income | 1,733 | 1,382 | 1,072 | ||||||
| Costs and expenses: | |||||||||
| Production | 217 | 188 | 153 | ||||||
| Marketing, including purchases from related parties | — | 47 | 34 | ||||||
| Other operating | 130 | 122 | 89 | ||||||
| Exploration | 52 | 57 | 28 | ||||||
| Depreciation, depletion and amortization | 590 | 583 | 556 | ||||||
| Impairments | 8 | 24 | 4 | ||||||
| Taxes other than income | 64 | 55 | 39 | ||||||
| General and administrative | 100 | 95 | 97 | ||||||
| Total costs and expenses | 1,161 | 1,171 | 1,000 | ||||||
| Income (loss) from operations | 572 | 211 | 72 | ||||||
| Net interest and other | (45 | ) | (71 | ) | (78 | ) | |||
| Loss on early extinguishment of debt | — | (5 | ) | — | |||||
| Other net periodic benefit costs | (3 | ) | (3 | ) | (10 | ) | |||
| Income (loss) from continuing operations before income taxes | 524 | 132 | (16 | ) | |||||
| Provision (benefit) for income taxes | 168 | 160 | 34 | ||||||
| Income (loss) from continuing operations | 356 | (28 | ) | (50 | ) | ||||
| Income (loss) from discontinued operations (a) | — | — | (4,907 | ) | |||||
| Net income (loss) | $ | 356 | $ | (28 | ) | $ | (4,957 | ) | |
| Adjusted Net Income | |||||||||
| Income (loss) from continuing operations | 356 | (28 | ) | (50 | ) | ||||
| Adjustments for special items from continuing operations (pre-tax): | |||||||||
| Net (gain) loss on dispositions | (257 | ) | (32 | ) | — | ||||
| Proved property impairments | 8 | 24 | — | ||||||
| Pension settlement | 4 | 7 | 14 | ||||||
| Unrealized (gain) loss on derivative instruments | 43 | 145 | (77 | ) | |||||
| Loss on extinguishment of debt | — | 5 | — | ||||||
| Other | — | (53 | ) | 1 | |||||
| Provision (benefit) for income taxes related to special items from continuing operations | — | (12 | ) | — | |||||
| Adjustments for special items from continuing operations: | $ | (202 | ) | $ | 84 | $ | (62 | ) | |
| Adjusted net income (loss) from continuing operations (b) | $ | 154 | $ | 56 | $ | (112 | ) | ||
| Income (loss) from discontinued operations (a) | — | — | (4,907 | ) | |||||
| Adjustments for special items from discontinued operations (pre-tax): | |||||||||
| Canadian oil sands business impairment (a) | — | — | 6,636 | ||||||
| Provision (benefit) for income taxes related to special items from discontinued operations (a) | — | — | (1,674 | ) | |||||
| Adjusted net income (loss) (b) | $ | 154 | $ | 56 | $ | (57 | ) | ||
| Per diluted share: | |||||||||
| Income (loss) from continuing operations | $ | 0.42 | $ | (0.03 | ) | $ | (0.06 | ) | |
| Net Income (loss) | $ | 0.42 | $ | (0.03 | ) | $ | (5.84 | ) | |
| Adjusted net income (loss) from continuing operations (b) | $ | 0.18 | $ | 0.07 | $ | (0.13 | ) | ||
| Adjusted net income (loss) (b) | $ | 0.18 | $ | 0.07 | $ | (0.07 | ) | ||
| Weighted average diluted shares | 852 | 850 | 849 | ||||||
| (a) The Company closed on its sale of the Canadian oil sands business in second quarter 2017. The Canadian oil sands business is reflected as discontinued operations in all historical periods presented. | |||||||||
| (b) Non-GAAP financial measure. See "Non-GAAP Measures" above for further discussion. | |||||||||
| Supplemental Statistics (Unaudited) | Three Months Ended | ||||||||
| Mar. 31 | Dec. 31 | Mar. 31 | |||||||
| (in millions) | 2018 | 2017 | 2017 | ||||||
| Segment income (loss) | |||||||||
| United States E&P | $ | 125 | $ | 76 | $ | (79 | ) | ||
| International E&P | 132 | 118 | 93 | ||||||
| Segment income (loss) | 257 | 194 | 14 | ||||||
| Not allocated to segments | 99 | (222 | ) | (64 | ) | ||||
| Loss from continuing operations | 356 | (28 | ) | (50 | ) | ||||
| Discontinued operations (a) | — | — | (4,907 | ) | |||||
| Net income (loss) | $ | 356 | $ | (28 | ) | $ | (4,957 | ) | |
| Exploration expenses | |||||||||
| United States E&P | $ | 51 | $ | 57 | $ | 26 | |||
| International E&P | 1 | — | 2 | ||||||
| Segment exploration expenses | 52 | 57 | 28 | ||||||
| Not allocated to segments | — | — | — | ||||||
| Total | $ | 52 | $ | 57 | $ | 28 | |||
| Cash flows | |||||||||
| Net cash provided by operating activities from continuing operations | $ | 649 | $ | 501 | $ | 501 | |||
| Minus: changes in working capital | (58 | ) | (28 | ) | (12 | ) | |||
| Minus: U.K. tax payment | — | (108 | ) | — | |||||
| Total net cash provided from continuing operations before changes in working capital and the U.K. tax payment (b) | $ | 707 | $ | 637 | $ | 513 | |||
| Net cash provided by operating activities from discontinued operations (a) | — | — | 95 | ||||||
| Cash additions to property, plant and equipment | $ | (662 | ) | $ | (669 | ) | $ | (283 | ) |
| (a) We entered into an agreement in first quarter 2017 to sell our Canadian business which is reflected as discontinued operations in all historical periods presented. | |||||||||
| (b) Non-GAAP financial measure. See "Non-GAAP Measures" above for further discussion. | |||||||||
| Three Months Ended | ||||||
| Mar. 31 | Dec. 31 | Mar. 31 | ||||
| (mboed) | 2018 | 2017 | 2017 | |||
| Net production | ||||||
| United States E&P | 284 | 262 | 208 | |||
| International E&P excluding Libya (a) | 114 | 121 | 122 | |||
| Total continuing operations, excluding Libya (a) | 398 | 383 | 330 | |||
| Libya (a) | 28 | 33 | 8 | |||
| Total continuing operations | 426 | 416 | 338 | |||
| (a) The Company closed on the sale of its Libya subsidiary in the first quarter 2018. | ||||||
| Three Months Ended | ||||||
| Mar. 31 | Dec. 31 | Mar. 31 | ||||
| (mboed) | 2018 | 2017 | 2017 | |||
| Net production | ||||||
| United States E&P | 284 | 262 | 208 | |||
| Less: Divestitures (a) | — | (1 | ) | (3 | ) | |
| Divestiture-adjusted United States E&P (a) | 284 | 261 | 205 | |||
| Divestiture-adjusted total continuing operations, excluding Libya (a) | 398 | 382 | 327 | |||
| Discontinued operations (b) | — | — | 45 | |||
| (a) Divestitures include the sale of certain conventional assets in Oklahoma in September 2017 and Colorado in October 2017. These production volumes have been removed from all historical periods shown in arriving at divestiture-adjusted United States E&P net production and divestiture-adjusted total continuing operations, excluding Libya. The Company closed on the sale of its Libya subsidiary in the first quarter 2018. | ||||||
| (b) The Company entered into an agreement in first quarter 2017 to sell its Canadian business which is reflected as discontinued operations in all historical periods presented. | ||||||
| Supplemental Statistics (Unaudited) | Three Months Ended | |||||
| Mar. 31 | Dec. 31 | Mar. 31 | ||||
| 2018 | 2017 | 2017 | ||||
| United States E&P - net sales volumes | ||||||
| Crude oil and condensate (mbbld) | 164 | 150 | 118 | |||
| Eagle Ford | 63 | 61 | 59 | |||
| Bakken | 61 | 58 | 39 | |||
| Oklahoma | 20 | 16 | 12 | |||
| Northern Delaware | 10 | 8 | — | |||
| Other United States (a) | 10 | 7 | 8 | |||
| Natural gas liquids (mbbld) | 50 | 49 | 40 | |||
| Eagle Ford | 21 | 23 | 20 | |||
| Bakken | 7 | 6 | 5 | |||
| Oklahoma | 18 | 18 | 13 | |||
| Northern Delaware | 3 | 1 | — | |||
| Other United States (a) | 1 | 1 | 2 | |||
| Natural gas (mmcfd) | 420 | 376 | 304 | |||
| Eagle Ford | 122 | 127 | 122 | |||
| Bakken | 35 | 26 | 21 | |||
| Oklahoma | 216 | 180 | 115 | |||
| Northern Delaware | 17 | 14 | — | |||
| Other United States (a) | 30 | 29 | 46 | |||
| Total United States E&P (mboed) | 284 | 262 | 208 | |||
| International E&P - net sales volumes | ||||||
| Crude oil and condensate (mbbld) | 63 | 58 | 37 | |||
| Equatorial Guinea | 15 | 20 | 18 | |||
| United Kingdom | 15 | 5 | 6 | |||
| Libya (b) | 28 | 29 | 12 | |||
| Other International | 5 | 4 | 1 | |||
| Natural gas liquids (mbbld) | 11 | 13 | 13 | |||
| Equatorial Guinea | 11 | 12 | 12 | |||
| United Kingdom | — | 1 | 1 | |||
| Natural gas (mmcfd) | 437 | 493 | 461 | |||
| Equatorial Guinea | 403 | 464 | 438 | |||
| United Kingdom (c) | 12 | 15 | 23 | |||
| Libya (b) | 22 | 14 | — | |||
| Total International E&P (mboed) | 147 | 153 | 126 | |||
| Total Company continuing operations - net sales volumes (mboed) | 431 | 415 | 334 | |||
| Net sales volumes of equity method investees | ||||||
| LNG (mtd) | 5,541 | 6,353 | 6,147 | |||
| Methanol (mtd) | 1,195 | 1,637 | 1,307 | |||
| Condensate and LPG (boed) | 12,416 | 14,605 | 14,546 | |||
| (a) Includes production from conventional onshore assets sold in the applicable periods. The sale of certain Oklahoma and Colorado assets closed in September 2017 and October 2017, respectively. | ||||||
| (b) The Company closed on the sale of its Libya subsidiary in the first quarter 2018. | ||||||
| (c) Includes natural gas acquired for injection and subsequent resale. | ||||||
| Supplemental Statistics (Unaudited) | Three Months Ended | ||||||||
| Mar. 31 | Dec. 31 | Mar. 31 | |||||||
| 2018 | 2017 | 2017 | |||||||
| United States E&P - average price realizations (a) | |||||||||
| Crude oil and condensate ($ per bbl) (c) | $ | 62.22 | $ | 55.46 | $ | 48.46 | |||
| Eagle Ford | 64.37 | 57.82 | 48.18 | ||||||
| Bakken | 60.20 | 54.42 | 48.75 | ||||||
| Oklahoma | 62.70 | 53.90 | 49.07 | ||||||
| Northern Delaware | 60.45 | 53.74 | — | ||||||
| Other United States (b) | 61.71 | 48.87 | 48.24 | ||||||
| Natural gas liquids ($ per bbl) | $ | 22.95 | $ | 23.60 | $ | 19.33 | |||
| Eagle Ford | 22.85 | 22.54 | 18.12 | ||||||
| Bakken | 23.57 | 24.09 | 15.35 | ||||||
| Oklahoma | 22.59 | 24.16 | 22.59 | ||||||
| Northern Delaware | 22.11 | 26.79 | — | ||||||
| Other United States (b) | 28.66 | 30.06 | 21.52 | ||||||
| Natural gas ($ per mcf) (d) | $ | 2.59 | $ | 2.65 | $ | 3.02 | |||
| Eagle Ford | 3.03 | 2.82 | 2.85 | ||||||
| Bakken | 3.25 | 2.82 | 3.27 | ||||||
| Oklahoma | 2.20 | 2.54 | 3.16 | ||||||
| Northern Delaware | 3.09 | 2.37 | — | ||||||
| Other United States (b) | 2.64 | 2.56 | 3.03 | ||||||
| International E&P - average price realizations | |||||||||
| Crude oil and condensate ($ per bbl) | $ | 66.23 | $ | 61.32 | $ | 50.41 | |||
| Equatorial Guinea | 51.94 | 52.92 | 43.27 | ||||||
| United Kingdom | 69.95 | 61.94 | 56.51 | ||||||
| Libya (e) | 73.75 | 68.31 | 58.36 | ||||||
| Other International | 55.29 | 48.89 | 44.70 | ||||||
| Natural gas liquids ($ per bbl) | $ | 1.83 | $ | 4.66 | $ | 3.86 | |||
| Equatorial Guinea (f) | 1.00 | 1.00 | 1.00 | ||||||
| United Kingdom | 44.53 | 45.71 | 38.99 | ||||||
| Natural gas ($ per mcf) | $ | 0.65 | $ | 0.59 | $ | 0.55 | |||
| Equatorial Guinea (f) | 0.24 | 0.24 | 0.24 | ||||||
| United Kingdom | 7.32 | 7.20 | 6.33 | ||||||
| Libya (e) | 4.57 | 5.03 | — | ||||||
| Benchmark | |||||||||
| WTI crude oil (per bbl) | $ | 62.89 | $ | 55.30 | $ | 51.78 | |||
| Brent (Europe) crude oil (per bbl)(g) | $ | 66.81 | $ | 61.53 | $ | 53.68 | |||
| Henry Hub natural gas (per mmbtu)(h) | $ | 3.00 | $ | 2.93 | $ | 3.32 | |||
| (a) Excludes gains or losses on commodity derivative instruments. | |||||||||
| (b) Includes production from conventional onshore assets sold in the applicable periods. The sale of certain Oklahoma and Colorado assets closed in September 2017 and October 2017, respectively. | |||||||||
| (c) Inclusion of crude oil derivative instruments would have affected average price realizations by a realized loss of $4.33 and $0.76 and realized gains of $0.34, for the first quarter of 2018, and fourth and first quarter of 2017, 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) The Company closed on the sale of its Libya subsidiary in the first quarter 2018. | |||||||||
| (f) 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. | |||||||||
| (g) Average of monthly prices obtained from Energy Information Administration website. | |||||||||
| (h) Settlement date average per mmbtu. | |||||||||
| Crude Oil | ||||||||
| 2018 | 2019 | 2020 | ||||||
| Second Quarter | Third Quarter | Fourth Quarter | First Quarter | Second Quarter | Third Quarter | Fourth Quarter | Full Year | |
| Three-Way Collars | ||||||||
| Volume (Bbls/day) | 85,000 | 95,000 | 95,000 | 40,000 | 40,000 | 10,000 | 10,000 | — |
| Weighted average price per Bbl: | ||||||||
| Ceiling | $56.38 | $57.65 | $57.65 | $66.46 | $66.46 | $70.00 | $70.00 | — |
| Floor | $51.65 | $52.11 | $52.11 | $53.50 | $53.50 | $52.00 | $52.00 | — |
| Sold put | $45.00 | $45.21 | $45.21 | $46.25 | $46.25 | $45.00 | $45.00 | — |
| Swaps | ||||||||
| Volume (Bbls/day) | 20,000 | — | — | — | — | — | — | — |
| Weighted average price per Bbl | $55.12 | — | — | — | — | — | — | — |
| Basis Swaps (a) | ||||||||
| Volume (Bbls/day) | 5,000 | 10,000 | 10,000 | 10,000 | 10,000 | 10,000 | 10,000 | 5,000 |
| Weighted average price per Bbl | $(0.60) | $(0.67) | $(0.67) | $(0.82) | $(0.82) | $(0.82) | $(0.82) | $(0.25) |
| (a) The basis differential price is between WTI Midland and WTI Cushing. | ||||||||
| Natural Gas | ||||||
| 2018 | ||||||
| Second Quarter | Third Quarter | Fourth Quarter | ||||
| Three-Way Collars | ||||||
| Volume (MMBtu/day) | 160,000 | 160,000 | 160,000 | |||
| Weighted average price per MMBtu | ||||||
| Ceiling | $3.61 | $3.61 | $3.61 | |||
| Floor | $3.00 | $3.00 | $3.00 | |||
| Sold put | $2.50 | $2.50 | $2.50 | |||