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| 8-K - 8-K - MARATHON OIL CORP | mro-20191231er8k.htm |
Marathon Oil Announces $2.2 Billion 2020 Development Capital Budget and Reports Fourth Quarter and Full Year 2019 Results
Eighth Consecutive Quarter of Organic Free Cash Flow
HOUSTON, Feb. 12, 2020 - Marathon Oil Corporation (NYSE:MRO) today announced its 2020 capital expenditure budget in addition to its fourth quarter and full year 2019 financial results. The 2020 plan is intended to continue building on the Company’s two year track record of execution on its framework for success: corporate returns improvement, sustainable free cash flow generation, and the return of capital to shareholders.
2020 Capital Budget Highlights
• | Disciplined total capital budget of $2.4 billion, down 11% from 2019; includes development capital budget of $2.2 billion, down 9% from 2019, and Resource Play Exploration (REx) capital of $200 million |
• | Underlying corporate returns improvement to continue outpacing production growth rates |
• | Forecasting sustainable organic free cash flow, post-dividend, at wide range of commodity prices with organic cash flow breakeven below $50/bbl WTI |
• | Cumulative two-year, post-dividend organic free cash flow of $600 million at flat $50/bbl WTI |
• | Cumulative two-year, post-dividend organic free cash flow of $2.1 billion at flat $60/bbl WTI |
• | Continue to prioritize return of capital to shareholders with a competitive dividend and $1.4 billion of share repurchase authorization outstanding |
• | Returned $1.4 billion of capital back to shareholders through dividends and share repurchases since beginning of 2018, representing 23% of operating cash flow; funded entirely by organic free cash flow generation |
• | 2020 annual U.S. oil production growth of 6% at the midpoint of guidance; comparable growth expected in 2021 on comparable development capital |
• | Resource Play Exploration (REx) capital spend of $200 million in 2020 primarily supports exploration and appraisal drilling in the Texas Delaware oil play and Louisiana Austin Chalk |
Full Year and Fourth Quarter 2019 Results
Marathon Oil reported full year 2019 net income of $480 million, or $0.59 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 $611 million, or $0.75 per diluted share. Net operating cash flow was $2,749 million, or $2,885 million before changes in working capital.
Marathon Oil reported fourth quarter 2019 net loss of $20 million, or $(0.03) 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 $55 million, or $0.07 per diluted share. Net operating cash flow was $700 million, or $685 million before changes in working capital.
2019 Highlights
• | Greater than 50% improvement in CROIC from 2017 on a price normalized basis |
• | Generated $410 million of organic free cash flow post-dividend in 2019; generated $110 million of organic free cash flow during fourth quarter |
• | Returned $510 million of capital back to shareholders during 2019, including execution of $350 million of share repurchases and $160 million of dividends; return of capital funded entirely by organic free cash flow generation |
• | Delivered annual, divestiture-adjusted U.S. oil production growth of 13% on unchanged $2.4 billion development capital budget; fourth quarter U.S. oil production averaged 196,000 net bopd, up 9% from prior year |
• | Achieved approximately 10% annual reduction in average completed well cost per lateral foot and approximately 15% annual reduction in U.S. unit production expense during 2019 |
• | Simplified International portfolio to free cash flow generating integrated business in Equatorial Guinea; divested U.K. and Kurdistan eliminating over $970 million of asset retirement obligations |
• | Enhanced resource base with addition of over 1,000 gross operated locations through success across all elements of returns focused resource capture framework; highlighted by organic enhancement in the Eagle Ford and Bakken, REx success in new Texas Delaware oil play, and accretive Eagle Ford bolt-on that closed in 2019 |
• | Investment grade credit rating at all primary rating agencies with conservative leverage metrics and low cash flow breakeven oil price |
• | Subsequent to quarter end, opportunistically added to hedges that now cover approximately 40% of 2020 annual U.S. crude oil production guidance at weighted average floor price of $55.00/bbl and weighted average ceiling price of $65.25/bbl |
“2019 was another year of differentiated execution for Marathon Oil as we comprehensively delivered on our framework for success for the second year in a row,” said Chairman, President and CEO Lee Tillman. “We continue to improve our underlying corporate returns, we’ve delivered positive organic free cash flow for eight consecutive quarters, and we’ve returned over 20% of our cash flow from operations back to our shareholders since the beginning of 2018. We improved our capital efficiency in 2019 through meaningful reductions in both completed well cost and unit production expense, and further optimized and simplified our portfolio. We also enhanced our resource base through success across all elements of our comprehensive resource capture framework, adding over three years of inventory through organic enhancement, Resource Play Exploration, and bolt-on acquisitions and trades. Looking ahead to 2020 and beyond, our focus on differentiated execution will remain unchanged. We’ll continue to be guided by our unwavering commitment to capital discipline and sustainability. This focus, along with our low organic free cash flow breakeven of $47/bbl in 2020, and even lower in 2021, will position Marathon Oil for success across a wide range of commodity price environments.”
United States (U.S.)
U.S. production averaged 328,000 net barrels of oil equivalent per day (boed) for fourth quarter 2019, including 196,000 net barrels of oil per day (bopd). Oil production was up 9% from the year-ago quarter on a divestiture-adjusted basis. U.S. unit production costs were $5.13 per barrel of oil equivalent (boe) for fourth quarter with full year unit production costs under $5.00 per boe and down approximately 15% compared to the prior year.
EAGLE FORD: Marathon Oil’s Eagle Ford production averaged 105,000 net boed for fourth quarter 2019. Oil production averaged 67,000 net bopd, as oil mix rose to 63% from 57% during the year-ago quarter. The Company brought 29 gross Company-operated wells to sales across Karnes, Atascosa and Gonzales counties with strong initial production rates. The third and fourth quarters of 2019 represented the two strongest quarters in the history of the asset on a 30-day initial production (IP) basis for oil. Completed well cost during fourth quarter averaged $5.1 million at an average lateral length of 6,400 feet. Fourth quarter average completed well cost per lateral foot was down 8% from the 2018 average.
BAKKEN: Marathon Oil’s Bakken production averaged 108,000 net boed in the fourth quarter 2019. Oil production averaged 86,000 net bopd. The Company brought 16 gross Company-operated wells to sales across the Myrmidon and Hector areas. The asset established new quarterly records for both drilling feet per day and completion stages per day during fourth quarter. The Company continues to deliver impressive capital efficiency and accretive financial returns, highlighted by a recent four-well pad in Myrmidon that achieved an average 30-day IP rate of 3,160 BOED (79% oil) at an average completed well cost of $4.3 million. The 16 gross Company-operated wells to sales during fourth quarter had an average completed well cost below $5 million, down 17% from the 2018 average.
OKLAHOMA: Marathon Oil’s Oklahoma production averaged 82,000 net boed in the fourth quarter 2019. Oil production averaged 24,000 net bopd, with oil mix rising to 29% from 24% during the year-ago quarter. The Company brought 14 gross Company-operated wells to sales, including nine wells targeting the Springer formation in the SCOOP. The nine Springer wells are demonstrating basin-leading productivity, with an average 30-day IP rate of 2,100 boed (79% oil). With a more concentrated program and strong production and cost performance, the Oklahoma asset successfully transitioned to positive free cash flow generation during fourth quarter.
NORTHERN DELAWARE: Marathon Oil’s Northern Delaware production averaged 28,000 net boed in the fourth quarter 2019. Oil production averaged 17,000 net bopd. The Company brought 13 gross Company-operated wells to sales, with a focus on the delineation of its Red Hills acreage. Since the transition to Red Hills delineation during fourth quarter, the Company has brought online nine Upper Wolfcamp wells with an average 30-day IP rate of 1,500 boed (74% oil) and four Bone Spring wells with an average 30-day IP rate of 2,270 boed (76% oil). The Company continues to advance learnings, reduce its cost structure, and improve margins, exiting the year with approximately 90% of water and oil on pipe.
Resource Capture
Fourth quarter REx capital expenditures totaled $168 million. Expenditures included two bolt-on acquisitions totaling $106 million that cored up the Company’s 60,000 net acres of contiguous leasehold in the Texas Delaware prospective for stacked Woodford and Meramec oil targets. The Company’s position in this new play was captured at an entry cost of less than $2,400 per acre. Full year 2019 REx capital expenditures totaled $277 million, consistent with prior guidance.
The Company’s 2020 REx capital expenditure budget of $200 million reflects a transition from acreage capture to exploration and appraisal drilling in two potential oil plays of scale. In the Texas Delaware, the Company’s third Woodford exploration well is on flowback, with early rates consistent with expectations. The Company has now brought online three Woodford exploration wells with average oil mix of 60%. In the Western Fairway of the Louisiana Austin Chalk, the Company’s first exploration well is on flowback and cleaning up with recent oil rates at 1,200 bopd (2,650 boed). The Company recently spud its second Louisiana Austin Chalk exploration well.
Outside of the REx program, in the fourth quarter Marathon Oil completed a bolt-on acquisition for approximately 18,000 contiguous and largely undeveloped net acres adjacent to the Company’s existing northeast Eagle Ford leasehold. The $191 million bolt-on acquisition included production of approximately 7,000 net boed (approx. 30% oil), associated midstream infrastructure, and cores up a 70-well, long lateral development with potential upside. The transaction had an effective date of Nov. 1, 2019, and closed on Dec. 31, 2019.
International
Equatorial Guinea production averaged 85,000 net boed for fourth quarter 2019, including 15,000 net bopd of oil. Unit production costs averaged $1.82 per boe.
Cash Flow and Development Capital
Net cash provided by operations was $700 million during fourth quarter 2019, or $685 million before changes in working capital.
Fourth quarter development capital expenditures were $556 million, bringing full year development capital to $2.4 billion, consistent with the original 2019 budget.
Organic free cash flow during fourth quarter totaled $111 million post-dividend, bringing full year organic free cash flow generation to $409 million.
Production Guidance
For full year 2020, the Company forecasts total U.S. oil production growth of 6% at the midpoint of guidance. Although oil production will not be meaningfully affected, full year 2020 International gas production will be impacted by scheduled maintenance activity in Equatorial Guinea during fourth quarter. Full year total Company oil growth is expected to outpace boe production growth, consistent with a focus on corporate returns.
First quarter 2020 U.S. oil production guidance is 192,000 to 202,000 net bopd. First quarter 2020 International oil production guidance is 12,000 to 16,000 net bopd.
Corporate
The Company executed $350 million of share repurchases during 2019, returning additional capital to shareholders beyond the $162 million of 2019 dividend payments. Since the beginning of 2018, Marathon Oil has repurchased $1.05 billion of its own shares, representing approximately 7% of its outstanding share count, funded entirely by post-dividend organic free cash flow.
Total liquidity as of Dec. 31 was approximately $3.9 billion, which consisted of $0.9 billion in cash and cash equivalents and an undrawn revolving credit facility of $3.0 billion.
The adjustments to net income for fourth quarter 2019 totaled $75 million before tax, primarily due to the income impact associated with unrealized losses on derivative instruments. Adjusted net income in the quarter was negatively impacted primarily by one-off and timing impacts totaling approximately $37 million.
As of Feb. 10, 2020, the Company’s open crude hedge positions for 2020 include an average of 80,000 bopd at a weighted average floor price of $55.00/bbl and a weighted average ceiling price of $65.25/bbl, hedged through three-way collars.
A slide deck and Quarterly Investor Packet will be posted to the Company’s website following this release today, Feb. 12. On Thursday, Feb. 13, 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, adjusted net income per share, organic free cash flow, net cash provided by operations before changes in working capital and organic finding and development costs.
Adjusted net income is defined as net income adjusted for gain/loss on dispositions, certain property impairments, unrealized derivative gain/loss on commodity instruments, pension settlement losses and other items that could be considered “non-operating” or “non-core” in nature. Management believes adjusted net income and adjusted net income per share are useful to investors as additional tools to meaningfully represent the Company’s operating performance and to compare Marathon to certain competitors.
Organic free cash flow is defined as net cash provided by operating activities adjusted for working capital, exploration costs (other than well costs), development capital expenditures, dividends, and EG LNG return of capital. Management believes this is useful to investors as a measure of the Company’s ability to fund its capital expenditure programs and dividend payments, service debt, and other distributions to stockholders. Management believes net cash provided by operations before changes in working capital is useful to investors to demonstrate the Company’s ability to generate cash quarterly or year-to-date by eliminating differences caused by the timing of certain working capital items.
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 in isolation or as alternatives to their most directly comparable GAAP financial measures. A reconciliation to their most directly comparable GAAP financial measures can be found in our investor package on our website at www.marathonoil.com and in the tables below. 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 capital budgets and allocations (including development capital budget and resource play leasing and exploration spend), future performance, organic free cash flow, 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, oil growth and other plans and objectives for future operations, are forward-looking statements. Words such as “anticipate,” “believe,” “could,” “estimate,” “expect,” “forecast,” “guidance,” “intend,” “may,” “outlook,” “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 Equatorial Guinea, including changes in foreign currency exchange rates, interest rates, inflation rates, and global and domestic market conditions; capital available for exploration and development; our ability to complete our announced acquisitions on the timeline currently anticipated, if at all; risks related to the Company’s hedging activities; well production timing; drilling and operating risks; availability of drilling rigs, materials and labor, including the costs associated therewith; 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, requirements or initiatives, including initiatives addressing the impact of global climate change, flaring, or water disposal; other geological, operating and economic considerations; and the risk factors, forward-looking statements and challenges and uncertainties described in the Company’s 2018 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:
Guy Baber: 713-296-1892
John Reid: 713-296-4380
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) | 2019 | 2019 | 2018 | 2019 | 2018 | ||||||||||
Revenues and other income: | |||||||||||||||
Revenues from contracts with customers | $ | 1,233 | $ | 1,249 | $ | 1,380 | $ | 5,063 | $ | 5,902 | |||||
Net gain (loss) on commodity derivatives | (44 | ) | 47 | 310 | (72 | ) | (14 | ) | |||||||
Income from equity method investments | 24 | 21 | 64 | 87 | 225 | ||||||||||
Net gain (loss) on disposal of assets | (6 | ) | 22 | (4 | ) | 50 | 319 | ||||||||
Other income | 8 | 6 | 15 | 62 | 150 | ||||||||||
Total revenues and other income | 1,215 | 1,345 | 1,765 | 5,190 | 6,582 | ||||||||||
Costs and expenses: | |||||||||||||||
Production | 169 | 163 | 205 | 712 | 842 | ||||||||||
Shipping, handling and other operating | 143 | 138 | 167 | 605 | 575 | ||||||||||
Exploration | 42 | 22 | 116 | 149 | 289 | ||||||||||
Depreciation, depletion and amortization | 616 | 622 | 613 | 2,397 | 2,441 | ||||||||||
Impairments | — | — | 25 | 24 | 75 | ||||||||||
Taxes other than income | 79 | 81 | 84 | 311 | 299 | ||||||||||
General and administrative | 93 | 82 | 88 | 356 | 394 | ||||||||||
Total costs and expenses | 1,142 | 1,108 | 1,298 | 4,554 | 4,915 | ||||||||||
Income from operations | 73 | 237 | 467 | 636 | 1,667 | ||||||||||
Net interest and other | (67 | ) | (64 | ) | (58 | ) | (244 | ) | (226 | ) | |||||
Other net periodic benefit costs | (6 | ) | 2 | (3 | ) | 3 | (14 | ) | |||||||
Loss on early extinguishment of debt | (3 | ) | — | — | (3 | ) | — | ||||||||
Income (loss) before income taxes | (3 | ) | 175 | 406 | 392 | 1,427 | |||||||||
Provision (benefit) for income taxes | 17 | 10 | 16 | (88 | ) | 331 | |||||||||
Net income (loss) | $ | (20 | ) | $ | 165 | $ | 390 | $ | 480 | $ | 1,096 | ||||
Adjusted Net Income (Loss) | |||||||||||||||
Net income (loss) | $ | (20 | ) | $ | 165 | $ | 390 | 480 | 1,096 | ||||||
Adjustments for special items (pre-tax): | |||||||||||||||
Net (gain) loss on disposal of assets | 6 | (22 | ) | 4 | (50 | ) | (319 | ) | |||||||
Proved property impairments | — | — | 25 | 24 | 75 | ||||||||||
Exploratory dry well costs, unproved property impairments and other | — | — | 40 | — | 40 | ||||||||||
Pension settlement | 10 | — | 5 | 12 | 21 | ||||||||||
Unrealized (gain) loss on derivative instruments | 55 | (33 | ) | (336 | ) | 124 | (267 | ) | |||||||
Reduction of U.K. ARO estimated costs | — | — | — | — | (121 | ) | |||||||||
Other | 4 | 1 | 6 | 28 | 6 | ||||||||||
Provision (benefit) for income taxes related to special items | — | — | (13 | ) | (7 | ) | 70 | ||||||||
Adjustments for special items | 75 | (54 | ) | (269 | ) | 131 | (495 | ) | |||||||
Adjusted net income (a) | $ | 55 | $ | 111 | $ | 121 | $ | 611 | $ | 601 | |||||
Per diluted share: | |||||||||||||||
Net income (loss) | $ | (0.03 | ) | $ | 0.21 | $ | 0.47 | $ | 0.59 | $ | 1.29 | ||||
Adjusted net income (a) | $ | 0.07 | $ | 0.14 | $ | 0.15 | $ | 0.75 | $ | 0.71 | |||||
Weighted average diluted shares | 800 | 803 | 829 | 810 | 847 | ||||||||||
(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) | 2019 | 2019 | 2018 | 2019 | 2018 | ||||||||||
Segment income | |||||||||||||||
United States | $ | 148 | $ | 180 | $ | 159 | $ | 675 | $ | 608 | |||||
International | 33 | 43 | 83 | 233 | 473 | ||||||||||
Not allocated to segments | (201 | ) | (58 | ) | 148 | (428 | ) | 15 | |||||||
Net income (loss) | $ | (20 | ) | $ | 165 | $ | 390 | $ | 480 | $ | 1,096 | ||||
Exploration expenses | |||||||||||||||
United States | $ | 42 | $ | 22 | $ | 76 | $ | 149 | $ | 246 | |||||
International | — | — | — | — | 3 | ||||||||||
Not allocated to segments | — | — | 40 | — | 40 | ||||||||||
Total | $ | 42 | $ | 22 | $ | 116 | $ | 149 | $ | 289 | |||||
Cash flows | |||||||||||||||
Net cash provided by operating activities | $ | 700 | $ | 737 | $ | 855 | $ | 2,749 | $ | 3,234 | |||||
Minus: changes in working capital | 15 | (20 | ) | 68 | (136 | ) | 23 | ||||||||
Net cash provided by operations before changes in working capital (a) | $ | 685 | $ | 757 | $ | 787 | $ | 2,885 | $ | 3,211 | |||||
Cash additions to property, plant and equipment | $ | (616 | ) | $ | (672 | ) | $ | (684 | ) | $ | (2,550 | ) | $ | (2,753 | ) |
(a) | Non-GAAP financial measure. See “Non-GAAP Measures” above for further discussion. |
Supplemental Statistics (Unaudited) | Three Months Ended | Year Ended | ||||
(In millions) | Dec. 31, 2019 | Dec. 31, 2019 | ||||
Organic Free Cash Flow | ||||||
Net cash provided by operating activities | $ | 700 | $ | 2,749 | ||
Adjustments: | ||||||
Changes in working capital | (15 | ) | 136 | |||
Exploration costs other than well costs | 13 | 35 | ||||
Development capital expenditures | (556 | ) | (2,407 | ) | ||
Dividends | (40 | ) | (162 | ) | ||
EG LNG return of capital and other | 9 | 58 | ||||
Organic free cash flow (a) | $ | 111 | $ | 409 | ||
(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 | ||||||
(mboed) | 2019 | 2019 | 2018 | 2019 | 2018 | |||||
Net production | ||||||||||
United States | 328 | 339 | 306 | 324 | 298 | |||||
International (a) | 85 | 87 | 105 | 92 | 114 | |||||
Total net production | 413 | 426 | 411 | 416 | 412 | |||||
(a) | The Company closed on the sale of its Libya subsidiary in the first quarter of 2018 and as such, international net production volumes for the year ended December 31, 2018 excludes 7 mboed related to Libya. |
Supplemental Statistics (Unaudited) | Three Months Ended | Year Ended | ||||||||
Dec. 31 | Sept. 30 | Dec. 31 | Dec. 31 | Dec. 31 | ||||||
(mboed) | 2019 | 2019 | 2018 | 2019 | 2018 | |||||
Net production | ||||||||||
United States | 328 | 339 | 306 | 324 | 298 | |||||
Less: Divestitures (a) | — | 1 | 2 | 1 | 6 | |||||
Total divestiture-adjusted United States | 328 | 338 | 304 | 323 | 292 | |||||
International | 85 | 87 | 105 | 92 | 114 | |||||
Less: Divestitures (b) | — | — | 12 | 7 | 16 | |||||
Total divestiture-adjusted International | 85 | 87 | 93 | 85 | 98 | |||||
Total net production divestiture-adjusted (a)(b) | 413 | 425 | 397 | 408 | 390 | |||||
(a) | The Company closed on the sale of certain United States non-core conventional assets in third quarter 2018, first quarter 2019, and third quarter 2019. The production volumes relating to these dispositions have been removed from all corresponding prior periods to derive the divestiture-adjusted United States net production. |
(b) | Divestitures include volumes associated with the following: (1) the sale of our U.K. business, which closed in third quarter 2019, (2) the sale of our non-operated interest in the Atrush block in Kurdistan, which closed in second quarter 2019, (3) the sale of our non-operated interest in the Sarsang block in Kurdistan, which closed in third quarter 2018, and (4) the sale of Libya, which closed in the first quarter of 2018. These production volumes have been removed from historical periods above in arriving at total divestiture-adjusted International net production. |
Supplemental Statistics (Unaudited) | Three Months Ended | Year Ended | ||||||||
Dec. 31 | Sept. 30 | Dec. 31 | Dec. 31 | Dec. 31 | ||||||
2019 | 2019 | 2018 | 2019 | 2018 | ||||||
United States - net sales volumes | ||||||||||
Crude oil and condensate (mbbld) | 196 | 201 | 180 | 190 | 171 | |||||
Eagle Ford | 67 | 63 | 62 | 63 | 63 | |||||
Bakken | 86 | 92 | 82 | 86 | 71 | |||||
Oklahoma | 24 | 23 | 16 | 21 | 18 | |||||
Northern Delaware | 16 | 18 | 14 | 16 | 12 | |||||
Other United States (a) | 3 | 5 | 6 | 4 | 7 | |||||
Natural gas liquids (mbbld) | 58 | 61 | 55 | 60 | 55 | |||||
Eagle Ford | 18 | 22 | 24 | 22 | 23 | |||||
Bakken | 12 | 9 | 6 | 9 | 7 | |||||
Oklahoma | 22 | 23 | 19 | 22 | 20 | |||||
Northern Delaware | 5 | 6 | 5 | 6 | 4 | |||||
Other United States (a) | 1 | 1 | 1 | 1 | 1 | |||||
Natural gas (mmcfd) | 444 | 462 | 422 | 438 | 429 | |||||
Eagle Ford | 121 | 134 | 127 | 130 | 129 | |||||
Bakken | 59 | 46 | 35 | 46 | 35 | |||||
Oklahoma | 216 | 229 | 192 | 210 | 213 | |||||
Northern Delaware | 41 | 36 | 42 | 36 | 26 | |||||
Other United States (a) | 7 | 17 | 26 | 16 | 26 | |||||
Total United States (mboed) | 328 | 339 | 305 | 323 | 298 | |||||
International - net sales volumes | ||||||||||
Crude oil and condensate (mbbld) | 13 | 16 | 29 | 20 | 39 | |||||
Equatorial Guinea | 13 | 16 | 16 | 15 | 17 | |||||
United Kingdom (b) | — | — | 10 | 4 | 11 | |||||
Libya (c) | — | — | — | — | 7 | |||||
Other International (d) | — | — | 3 | 1 | 4 | |||||
Natural gas liquids (mbbld) | 9 | 10 | 10 | 9 | 11 | |||||
Equatorial Guinea | 9 | 10 | 10 | 9 | 11 | |||||
Natural gas (mmcfd) | 363 | 373 | 411 | 371 | 435 | |||||
Equatorial Guinea | 363 | 373 | 400 | 365 | 416 | |||||
United Kingdom (b)(e) | — | — | 11 | 6 | 14 | |||||
Libya (c) | — | — | — | — | 5 | |||||
Total International (mboed) | 83 | 88 | 108 | 91 | 122 | |||||
Total Company - net sales volumes (mboed) | 411 | 427 | 413 | 414 | 420 | |||||
Net sales volumes of equity method investees | ||||||||||
LNG (mtd) | 5,180 | 4,590 | 5,384 | 4,933 | 5,805 | |||||
Methanol (mtd) | 1,153 | 1,036 | 1,119 | 1,082 | 1,241 | |||||
Condensate and LPG (boed) | 11,832 | 11,586 | 15,071 | 11,104 | 13,034 | |||||
(a) | Includes sales volumes from the sale of certain non-core proved properties in our United States segment. |
(b) | The Company closed on the sale of its U.K. business on July 1, 2019. |
(c) | The Company closed on the sale of its Libya subsidiary in the first quarter of 2018. |
(d) | Other International includes volumes for the Atrush block in Kurdistan, which was sold in the second quarter of 2019. |
(e) | Includes natural gas acquired for injection and subsequent resale. |
Supplemental Statistics (Unaudited) | Three Months Ended | Year Ended | |||||||||||||
Dec. 31 | Sept. 30 | Dec. 31 | Dec. 31 | Dec. 31 | |||||||||||
2019 | 2019 | 2018 | 2019 | 2018 | |||||||||||
United States - average price realizations (a) | |||||||||||||||
Crude oil and condensate ($ per bbl) (b) | $ | 54.83 | $ | 55.09 | $ | 56.01 | $ | 55.80 | $ | 63.11 | |||||
Eagle Ford | 57.63 | 57.99 | 63.27 | 59.06 | 67.19 | ||||||||||
Bakken | 51.98 | 53.48 | 51.11 | 53.65 | 60.39 | ||||||||||
Oklahoma | 55.49 | 55.09 | 58.42 | 55.78 | 64.63 | ||||||||||
Northern Delaware | 57.08 | 54.16 | 48.04 | 54.04 | 55.23 | ||||||||||
Other United States (c) | 56.26 | 51.74 | 60.41 | 57.47 | 63.11 | ||||||||||
Natural gas liquids ($ per bbl) | $ | 15.47 | $ | 11.37 | $ | 24.71 | $ | 14.22 | $ | 24.54 | |||||
Eagle Ford | 15.72 | 11.40 | 21.46 | 14.27 | 24.08 | ||||||||||
Bakken | 13.12 | 7.16 | 19.01 | 13.48 | 24.98 | ||||||||||
Oklahoma | 17.30 | 13.20 | 29.55 | 14.66 | 24.38 | ||||||||||
Northern Delaware | 12.35 | 10.02 | 28.99 | 13.15 | 26.30 | ||||||||||
Other United States (c) | 13.98 | 15.21 | 26.68 | 16.43 | 28.63 | ||||||||||
Natural gas ($ per mcf) | $ | 2.10 | $ | 1.92 | $ | 3.27 | $ | 2.18 | $ | 2.65 | |||||
Eagle Ford | 2.40 | 2.29 | 3.69 | 2.54 | 3.09 | ||||||||||
Bakken | 2.31 | 1.83 | 3.46 | 2.34 | 2.95 | ||||||||||
Oklahoma | 1.95 | 1.75 | 3.22 | 2.04 | 2.38 | ||||||||||
Northern Delaware | 1.72 | 0.84 | 1.80 | 1.17 | 2.08 | ||||||||||
Other United States (c) | 1.89 | 3.69 | 3.65 | 2.81 | 2.73 | ||||||||||
International - average price realizations | |||||||||||||||
Crude oil and condensate ($ per bbl) | $ | 48.26 | $ | 46.04 | $ | 58.25 | $ | 53.09 | $ | 64.25 | |||||
Equatorial Guinea | 48.26 | 46.04 | 46.35 | 48.99 | 55.28 | ||||||||||
United Kingdom (d) | — | — | 78.49 | 67.99 | 74.34 | ||||||||||
Libya (e) | — | — | — | — | 73.75 | ||||||||||
Other International (f) | — | — | 52.52 | 51.24 | 58.89 | ||||||||||
Natural gas liquids ($ per bbl) | $ | 1.00 | $ | 1.00 | $ | 2.25 | $ | 1.40 | $ | 2.27 | |||||
Equatorial Guinea (g) | 1.00 | 1.00 | 1.00 | 1.00 | 1.00 | ||||||||||
United Kingdom (d) | — | — | 33.44 | 37.88 | 41.66 | ||||||||||
Natural gas ($ per mcf) | $ | 0.24 | $ | 0.24 | $ | 0.49 | $ | 0.33 | $ | 0.54 | |||||
Equatorial Guinea (g) | 0.24 | 0.24 | 0.24 | 0.24 | 0.24 | ||||||||||
United Kingdom (d) | — | — | 9.13 | 5.67 | 8.03 | ||||||||||
Libya (e) | — | — | — | — | 4.57 | ||||||||||
Benchmark | |||||||||||||||
WTI crude oil (per bbl) | $ | 56.87 | $ | 56.44 | $ | 59.34 | $ | 57.04 | $ | 64.90 | |||||
Brent (Europe) crude oil (per bbl) (h) | $ | 63.41 | $ | 61.93 | $ | 67.71 | $ | 64.36 | $ | 71.06 | |||||
Mont Belvieu NGLs (per bbl) (i) | $ | 17.15 | $ | 15.16 | $ | 25.09 | $ | 17.81 | $ | 26.75 | |||||
Henry Hub natural gas (per mmbtu) (j) | $ | 2.50 | $ | 2.23 | $ | 3.64 | $ | 2.63 | $ | 3.09 | |||||
(a) | Excludes gains or losses on commodity derivative instruments. |
(b) | Inclusion of realized gains (losses) on crude oil derivative instruments would have affected average price realizations by $0.58, $0.72, $(1.50), $0.67, and $(4.60), for the fourth and third quarter 2019, the fourth quarter 2018, and the years 2019 and 2018, respectively. |
(c) | Includes sales volumes from the sale of certain non-core proved properties in our United States segment. |
(d) | The Company closed on the sale of its U.K. business on July 1, 2019. |
(e) | The Company closed on the sale of its Libya subsidiary in the first quarter of 2018. |
(f) | Other International includes volumes for the Atrush block in Kurdistan, which was sold in the second quarter of 2019. |
(g) | 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 segment. |
(h) | Average of monthly prices obtained from Energy Information Administration website. |
(i) | Bloomberg Finance LLP: Y-grade Mix NGL of 55% ethane, 25% propane, 5% butane, 8% isobutane and 7% natural gasoline. |
(j) | Settlement date average per mmbtu. |
Q1 2020 Production Guidance | Oil Production (mbbld) | Equivalent Production (mboed) | |||||||||||||||
Q1 2020 | Q4 2019 | Q1 2019 | Q1 2020 | Q4 2019 | Q1 2019 | ||||||||||||
Low | High | Divestiture-Adjusted | Divestiture-Adjusted | Low | High | Divestiture-Adjusted | Divestiture-Adjusted | ||||||||||
Net production | |||||||||||||||||
United States | 192 | 202 | 196 | 176 | 325 | 335 | 328 | 294 | |||||||||
International | 12 | 16 | 15 | 14 | 75 | 85 | 85 | 78 | |||||||||
Total net production | 204 | 218 | 211 | 190 | 400 | 420 | 413 | 372 | |||||||||
Estimated Net Proved Reserves (mmboe) | U.S. | Int'l | Total | ||||
As of December 31, 2018 | 1,078 | 203 | 1,281 | ||||
Additions | 91 | — | 91 | ||||
Revisions | (23 | ) | 24 | 1 | |||
Acquisitions | 18 | — | 18 | ||||
Dispositions | (11 | ) | (24 | ) | (35 | ) | |
Production | (117 | ) | (34 | ) | (151 | ) | |
As of December 31, 2019 | 1,036 | 169 | 1,205 | ||||
Organic Changes in Reserves (excluding dispositions) (mmboe) | 110 | ||||||
Production (excluding dispositions) (mmboe) | 149 | ||||||
Reserve Replacement Ratio (excluding dispositions) | 74 | % | |||||
Organic Changes in Reserves (excluding dispositions and acquisitions) (mmboe) | 92 | ||||||
Production (excluding dispositions) (mmboe) | 149 | ||||||
Organic Reserve Replacement Ratio (excluding dispositions and acquisitions) | 62 | % | |||||
Finding Costs (In millions, except as indicated) | 2019 | ||||||
Property Acquisition Costs - Proved | $ | 93 | |||||
Property Acquisition Costs - Unproved | 282 | ||||||
Exploration | 862 | ||||||
Development | 1,699 | ||||||
Total Company - Costs Incurred | $ | 2,936 | |||||
Cost Incurred | $ | 2,936 | |||||
Organic Changes in Reserves (excluding dispositions) (mmboe) | 110 | ||||||
Finding and Development Costs per BOE | $ | 26.69 | |||||
Costs Incurred | $ | 2,936 | |||||
Property Acquisition Costs (Proved and Unproved) | (375 | ) | |||||
Capitalized Asset Retirement Costs | (80 | ) | |||||
Organic Finding and Development Costs (a) | $ | 2,481 | |||||
Organic Changes in Reserves (excluding dispositions and acquisitions) (mmboe) | 92 | ||||||
Organic Finding and Development Costs per BOE (a) | $ | 26.97 | |||||
(a) | Non-GAAP financial measure. See “Non-GAAP Measures” above for further discussion. |
The following table sets forth outstanding derivative contracts as of February 10, 2020, and the weighted average prices for those contracts:
2020 | 2021 | |||||||||||||||||||||
Crude Oil | First Quarter | Second Quarter | Third Quarter | Fourth Quarter | Full Year | |||||||||||||||||
NYMEX WTI Three-Way Collars (a) | ||||||||||||||||||||||
Volume (Bbls/day) | 80,000 | 80,000 | 80,000 | 80,000 | — | |||||||||||||||||
Weighted average price per Bbl: | ||||||||||||||||||||||
Ceiling | $ | 66.12 | $ | 66.12 | $ | 64.40 | $ | 64.40 | $ | — | ||||||||||||
Floor | $ | 55.00 | $ | 55.00 | $ | 55.00 | $ | 55.00 | $ | — | ||||||||||||
Sold put | $ | 47.75 | $ | 47.75 | $ | 48.00 | $ | 48.00 | $ | — | ||||||||||||
Basis Swaps - Argus WTI Midland (b) | ||||||||||||||||||||||
Volume (Bbls/day) | 15,000 | 15,000 | 15,000 | 15,000 | — | |||||||||||||||||
Weighted average price per Bbl | $ | (0.94 | ) | $ | (0.94 | ) | $ | (0.94 | ) | $ | (0.94 | ) | $ | — | ||||||||
Basis Swaps - NYMEX WTI / ICE Brent (c) | ||||||||||||||||||||||
Volume (Bbls/day) | 5,000 | 5,000 | 5,000 | 5,000 | 808 | |||||||||||||||||
Weighted average price per Bbl | $ | (7.24 | ) | $ | (7.24 | ) | $ | (7.24 | ) | $ | (7.24 | ) | $ | (7.24 | ) | |||||||
Natural Gas | ||||||||||||||||||||||
Three-Way Collars | ||||||||||||||||||||||
Volume (MMBtu/day) | 100,000 | — | — | — | — | |||||||||||||||||
Weighted average price per MMBtu: | ||||||||||||||||||||||
Ceiling | $ | 3.32 | $ | — | $ | — | $ | — | $ | — | ||||||||||||
Floor | $ | 2.75 | $ | — | $ | — | $ | — | $ | — | ||||||||||||
Sold put | $ | 2.25 | $ | — | $ | — | $ | — | $ | — | ||||||||||||
(a) | Included in the table above, are 20,000 bbls/day of three-way collars for 2020 with a ceiling price of $66.37, a floor price of $55.00, and a sold put price of $48.00 which were entered into between January 1, 2020 and February 10, 2020. |
(b) | The basis differential price is indexed against Argus WTI Midland. |
(c) | The basis differential price is indexed against Intercontinental Exchange (“ICE”) Brent and NYMEX WTI. |