Exhibit
Marathon Oil Reports Third Quarter 2019 Results
7th Consecutive Quarter of Free Cash Flow Supports Ongoing Return of Capital to Shareholders; Added Over 1,000 Operated Locations Through Comprehensive Resource Capture Framework
HOUSTON, Nov. 6, 2019 - Marathon Oil Corporation (NYSE:MRO) today reported third quarter 2019 net income of $165 million, or $0.21 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 $111 million, or $0.14 per diluted share. Net operating cash flow was $737 million, or $757 million before changes in working capital.
Highlights
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• | $81 million of organic free cash flow post-dividend, bringing year-to-date organic free cash flow to $298 million |
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• | Approximately $300 million of year-to-date share repurchases in addition to $122 million of dividend payments |
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• | U.S. oil production averaged 201,000 net bopd during third quarter, up 17% from year-ago quarter, divestiture-adjusted, and above top end of guidance range |
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• | Company oil production averaged 216,000 net bopd during third quarter, up 14% from year-ago quarter, divestiture-adjusted, and at top end of guidance range |
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• | Development capital spend of $646 million third quarter; annual $2.4 billion development capital budget remains unchanged |
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• | U.S. and International unit production costs at lowest quarterly averages since becoming an independent E&P company |
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• | Added over 1,000 operated locations, equivalent to about three years of inventory, through success across all elements of returns focused resource capture framework; highlighted by organic enhancement in the Eagle Ford and Bakken, Resource Play Exploration (REx) success in a new Texas Delaware oil play, and an accretive bolt-on in the Eagle Ford |
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▪ | Established a new Texas Delaware oil play with over 60,000 contiguous net acres at low entry cost of less than $2,400 per acre; initial two wells encouraging with strong oil productivity, low water cut and shallow decline |
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▪ | Signed agreement for Eagle Ford bolt-on of approximately 18,000 contiguous and largely undeveloped net acres; adjacent to existing Company leasehold and cores up 70 future drilling locations in a high return development area |
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• | Recently closed on three financing transactions that are collectively leverage neutral, extend maturities, generate annual cash cost savings, and reflect Marathon Oil’s commitment to maintaining a strong balance sheet and investment grade credit rating at all primary ratings agencies |
“Third quarter again featured exceptional operational performance across our advantaged multi-basin portfolio that is translating to differentiated financial outcomes in our peer space,” said Chairman, President and CEO Lee Tillman. “We’re driving our corporate returns higher, have just reported our seventh consecutive quarter of organic free cash flow generation, and have returned over 20% of our year-to-date cash flow from operations back to our shareholders. Since the beginning of 2018, we’ve repurchased $1 billion of our own shares, representing approximately 7% of outstanding share count, funded entirely by post-dividend organic free cash flow. Additionally,
we are generating success across all elements of our comprehensive resource capture framework. We’ve added about three years of new inventory company-wide, while upgrading the returns on hundreds of drilling locations in the Bakken and Eagle Ford. Our REx team is advancing exploration and appraisal activity in two oil plays of scale, with encouraging early well results in a new Texas Delaware oil play. We also signed an agreement for a synergistic bolt-on acquisition in the Eagle Ford.
“Looking ahead to 2020, our framework for success will not change: corporate returns first, free cash flow at conservative pricing and return of capital back to shareholders. We expect our 2020 planning basis to be set on $50/bbl WTI with an enterprise free cash flow break-even below that level. With our focus on delivering financial outcomes competitive with the broader market, we’re planning for capital spend to decrease year-over-year and accordingly for our U.S. oil growth to moderate. Organic enhancement success and industry leading returns support a higher relative capital allocation to the Eagle Ford and Bakken, driving growth for both assets, as we take full advantage of our multi-basin model. We’ll continue to be guided by our unwavering commitment to capital discipline and low enterprise breakeven oil price to position Marathon Oil for success across a wide range of commodity price environments in 2020 and beyond.”
United States (U.S.)
U.S. production averaged 339,000 net barrels of oil equivalent per day (boed) for third quarter 2019, including 201,000 net barrels of oil per day (bopd). Oil production was above the top end of the third quarter guidance range and up 17% from the year-ago quarter on a divestiture-adjusted basis. U.S. unit production costs were $4.75 per barrel of oil equivalent (boe), down 23% from the year-ago quarter, the lowest quarterly average unit production costs since becoming an independent exploration and production company in 2011.
EAGLE FORD: Marathon Oil’s Eagle Ford production averaged 107,000 net boed in the third quarter 2019. The Company brought 35 gross Company-operated wells to sales in the quarter. Third quarter activity again featured impressive results in both core Karnes County and the expanded core of Atascosa County, highlighted by a new quarterly record for average 30-day initial oil productivity for the asset. Karnes activity included five Austin Chalk wells that achieved an average 30-day initial production (IP) rate of 2,550 boed (78% oil). In Atascosa, nine wells achieved an average 30-day IP rate of 1,780 boed (87% oil). The Middle McCowen four-well pad in Atascosa featured average lateral lengths of 10,900 feet, a new lateral length record for the asset, highlighting optionality for capital efficient, long lateral development across parts of Atascosa County. Completed well cost per lateral foot remains on a declining trend, with the third quarter average approximately 10% below 2018.
BAKKEN: Marathon Oil’s Bakken production averaged 109,000 net boed in the third quarter 2019. The Company brought 30 gross Company-operated wells to sales. The Company continues to deliver impressive capital efficiency, highlighted by strong productivity and declining completed well costs, which averaged $4.9 million, or about 20% below the 2018 average. The successful delineation of Marathon Oil’s broader Hector acreage continued during third quarter, with the four-well Herbert pad in South Hector achieving an average 30-day IP rate of 1,720 boed (86% oil) with an average completed well cost of approximately $4.5 million.
OKLAHOMA: Marathon Oil’s Oklahoma production averaged 84,000 net boed in the third quarter 2019. The Company brought 19 gross Company-operated wells to sales. Marathon Oil continues to deliver strong results from the overpressured STACK, where the Marjorie and Lloyd four-well per section infills achieved an average 30-day IP rate of 1,740 boed (66% oil). The average completed well cost for the Marjorie and Lloyd pads was $6.3 million normalized to a 10,000 foot lateral. In the SCOOP, Marathon Oil brought online three Springer wells with strong early performance, achieving an average 30-day IP rate of 1,460 boed (72% oil), or 325 boed per 1,000-foot lateral.
NORTHERN DELAWARE: Marathon Oil’s Northern Delaware production averaged 30,000 net boed in the third quarter 2019. The Company brought 10 gross Company-operated wells to sales, including a mix of development and delineation wells. Marathon Oil continues to make significant progress in advancing learnings, reducing its cost structure and improving margins. Third quarter again featured strong Upper Wolfcamp productivity in the Malaga area, where five development wells achieved an average 30-day IP rate of 1,850 boed (62% oil), or 365 boed per 1,000-foot lateral, with completed well costs per lateral foot 20% below the 2018 average.
Resource Capture
Marathon Oil is successfully executing across all three elements of its comprehensive framework for resource capture and inventory enhancement. The combination of organic enhancement in the Eagle Ford and Bakken, REx success in a new Texas Delaware oil play, and an accretive bolt-on in the Eagle Ford has added over 1,000 operated locations and meaningfully upgraded the returns for hundreds of locations in the Eagle Ford and Bakken.
Through its REx program, Marathon Oil is now advancing exploration and appraisal activity in two oil plays of scale: a new Texas Delaware oil play and the Louisiana Austin Chalk.
In the Texas Delaware, Marathon Oil has established over 60,000 net acres of contiguous leasehold prospective for stacked Woodford and Meramec oil targets. Two wells have been drilled and completed with initial results demonstrating strong productivity, low water cuts, and shallow decline profiles. The Company’s position in this new play was captured at an entry cost of less than $2,400 per acre through a combination of organic leasing and targeted acquisitions, with some acreage pending close in the fourth quarter.
Third quarter REx capital expenditures were $35 million, with year-to-date expenditures of $109 million through end of third quarter. Including the leasing and acquisitions to core up its new Texas Delaware play which are anticipated to close in fourth quarter, full year 2019 REx capital spending is now expected to be approximately $280 million, an increase of $80 million from prior guidance of $200 million.
In the Louisiana Austin Chalk, Marathon Oil is progressing exploration drilling and acquiring 3D seismic data. Consistent with its focus on capital discipline, the Company has secured Equinor as a non-operating, 25% working interest partner in the Louisiana Austin Chalk play. On a cash basis, this transaction helps fund incremental REx capital spending relative to prior guidance.
Outside of the REx program, in the fourth quarter Marathon Oil signed an agreement to acquire approximately 18,000 contiguous and largely undeveloped net acres adjacent to the Company’s existing northeast Eagle Ford leasehold. The $185 million bolt-on includes approximately 7,000 net boed of current production, associated midstream infrastructure, and cores up a 70-well, long lateral development with potential upside. The transaction has an effective date of Nov. 1, 2019 and is expected to close by Jan. 31, 2020.
International
International production averaged 87,000 net boed for third quarter 2019. Unit production costs averaged $1.98 per boe. Marathon Oil closed on the sale of its U.K. business July 1, removing $966 million of asset retirement obligations. Coupled with the second quarter close on the sale of the Company’s last block in Kurdistan, Marathon Oil’s international portfolio has been simplified to only include the free cash flow generative integrated business in Equatorial Guinea.
Cash Flow and Development Capital
Net cash provided by operations was $737 million during third quarter 2019, or $757 million before changes in working capital.
Third quarter development capital expenditures were $646 million, with year-to-date development capital of $1.9 billion. The Company’s 2019 development capital budget remains unchanged at $2.4 billion.
Organic free cash flow during third quarter totaled $81 million post-dividend, bringing year-to-date organic free cash flow generation to $298 million.
Production Guidance
For fourth quarter 2019, the Company forecasts total U.S. oil production of 190,000 to 200,000 net bopd. Fourth quarter 2019 international oil production guidance is 12,000 to 16,000 net bopd. Full year 2019 divestiture-adjusted oil production growth guidance is now expected to be 11% for total Company and 13% for U.S., above initial guidance of 10% and 12% respectively.
Corporate
The Company has executed $300 million of year-to-date share repurchases, returning additional capital to shareholders beyond the $122 million of year-to-date dividend payments. Since the beginning of 2018, Marathon Oil has repurchased $1 billion of its own shares, representing approximately 7% of its outstanding share count, funded entirely by post-dividend organic free cash flow generation of over $1 billion over the same period.
The Company recently completed three separate transactions that together will further strengthen the balance sheet and generate annualized cash cost savings of approximately $6 million. On Sept. 24, 2019, the Company entered into a Fourth Amendment to its Amended and Restated Credit Agreement to extend the maturity date to 2023 and reduce the size from $3.4 billion to $3.0 billion. On Oct. 1, 2019, the Company closed a remarketing to investors of $600 million of sub-series A bonds with tenors ranging from 3.5 to 7 years achieving a weighted average coupon rate of 2.1%. On Oct. 3, 2019, the Company closed the early redemption of its $600 million 2.7% Senior Unsecured Notes due 2020. The Company’s next debt maturity will be in 2022. Together, the three transactions are leverage neutral, extend maturities, and reflect Marathon Oil’s ongoing commitment to maintaining a strong balance sheet. Marathon Oil is rated investment grade at all three primary credit ratings agencies.
Total liquidity as of Sept. 30 was approximately $4.2 billion, which consisted of $1.2 billion in cash and cash equivalents and an undrawn revolving credit facility of $3.0 billion.
The adjustments to net income for third quarter 2019 totaled $54 million before tax, primarily due to the income impact associated with unrealized gains on derivative instruments, coupled with gains on disposal of assets.
As of Nov. 5, 2019, the Company’s open crude hedge positions for 2019 include an average of 80,000 bopd at a weighted average floor price of $56.75 per barrel and a weighted average ceiling price of $74.19 per bbl, hedged through three-way collars. The Company has also hedged 42,945 bopd of 2020 oil production at a weighted average floor price of $55.00 per barrel and a weighted average ceiling price of $65.58 per barrel.
A slide deck and Quarterly Investor Packet will be posted to the Company’s website following this release today, Nov. 6. On Thursday, Nov. 7, 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.
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Non-GAAP Measures
In analyzing and planning for its business, Marathon Oil supplements its use of GAAP financial measures with non-GAAP financial measures, including adjusted net income, adjusted net income per share, organic free cash flow and net cash provided by operations before changes in working capital.
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 also uses net cash provided by operations before changes in working capital 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 2019 capital budget 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 the jurisdictions in which the Company operates, 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
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Consolidated Statements of Income (Unaudited) | Three Months Ended |
| Sept. 30 |
| June 30 |
| Sept. 30 |
|
(In millions, except per share data) | 2019 |
| 2019 |
| 2018 |
|
Revenues and other income: | | | |
Revenues from contracts with customers | $ | 1,249 |
| $ | 1,381 |
| $ | 1,538 |
|
Net gain (loss) on commodity derivatives | 47 |
| 16 |
| (70 | ) |
Income from equity method investments | 21 |
| 31 |
| 64 |
|
Net gain (loss) on disposal of assets | 22 |
| (8 | ) | 16 |
|
Other income | 6 |
| 13 |
| 119 |
|
Total revenues and other income | 1,345 |
| 1,433 |
| 1,667 |
|
Costs and expenses: | |
| | |
Production | 163 |
| 193 |
| 215 |
|
Shipping, handling and other operating | 138 |
| 170 |
| 152 |
|
Exploration | 22 |
| 26 |
| 56 |
|
Depreciation, depletion and amortization | 622 |
| 605 |
| 626 |
|
Impairments | — |
| 18 |
| 8 |
|
Taxes other than income | 81 |
| 79 |
| 86 |
|
General and administrative | 82 |
| 87 |
| 101 |
|
Total costs and expenses | 1,108 |
| 1,178 |
| 1,244 |
|
Income from operations | 237 |
| 255 |
| 423 |
|
Net interest and other | (64 | ) | (64 | ) | (58 | ) |
Other net periodic benefit costs | 2 |
| 2 |
| (8 | ) |
Income before income taxes | 175 |
| 193 |
| 357 |
|
Provision (benefit) for income taxes | 10 |
| 32 |
| 103 |
|
Net income | $ | 165 |
| $ | 161 |
| $ | 254 |
|
| | | |
Adjusted Net Income | | | |
Net income | $ | 165 |
| $ | 161 |
| $ | 254 |
|
Adjustments for special items (pre-tax): | | | |
Net (gain) loss on disposal of assets | (22 | ) | 8 |
| (16 | ) |
Proved property impairments | — |
| 18 |
| 8 |
|
Pension settlement | — |
| 2 |
| 10 |
|
Unrealized (gain) loss on derivative instruments | (33 | ) | (11 | ) | (19 | ) |
Reduction of U.K. ARO estimated costs | — |
| — |
| (113 | ) |
Other | 1 |
| 11 |
| — |
|
Benefit for income taxes related to special items | — |
| — |
| 76 |
|
Adjustments for special items | (54 | ) | 28 |
| (54 | ) |
Adjusted net income (a) | $ | 111 |
| $ | 189 |
| $ | 200 |
|
Per diluted share: | | | |
Net income | $ | 0.21 |
| $ | 0.20 |
| $ | 0.30 |
|
Adjusted net income (a) | $ | 0.14 |
| $ | 0.23 |
| $ | 0.24 |
|
Weighted average diluted shares | 803 |
| 814 |
| 849 |
|
| |
(a) | Non-GAAP financial measure. See “Non-GAAP Measures” above for further discussion. |
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| | | | | | | | | |
Supplemental Statistics (Unaudited) | Three Months Ended |
| Sept. 30 |
| June 30 |
| Sept. 30 |
|
(In millions) | 2019 |
| 2019 |
| 2018 |
|
Segment income | | | |
United States | $ | 180 |
| $ | 215 |
| $ | 201 |
|
International | 43 |
| 96 |
| 116 |
|
Segment income | 223 |
| 311 |
| 317 |
|
Not allocated to segments | (58 | ) | (150 | ) | (63 | ) |
Net income | $ | 165 |
| $ | 161 |
| $ | 254 |
|
Exploration expenses | | | |
United States | $ | 22 |
| $ | 26 |
| $ | 55 |
|
International | — |
| — |
| 1 |
|
Total | $ | 22 |
| $ | 26 |
| $ | 56 |
|
Cash flows | |
| | |
Net cash provided by operating activities | $ | 737 |
| $ | 797 |
| $ | 963 |
|
Minus: changes in working capital | (20 | ) | 26 |
| 103 |
|
Net cash provided by operations before changes in working capital (a) | $ | 757 |
| $ | 771 |
| $ | 860 |
|
| | | |
Cash additions to property, plant and equipment | $ | (672 | ) | $ | (647 | ) | $ | (769 | ) |
| |
(a) | Non-GAAP financial measure. See “Non-GAAP Measures” above for further discussion. |
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| | | | | | |
Supplemental Statistics (Unaudited) | Three Months Ended | Nine Months Ended |
(In millions) | Sept. 30, 2019 | Sept. 30, 2019 |
Organic Free Cash Flow | | |
Net cash provided by operating activities | $ | 737 |
| $ | 2,049 |
|
Adjustments: | | |
Changes in working capital | 20 |
| 151 |
|
Exploration costs other than well costs | 6 |
| 22 |
|
Development capital expenditures | (646 | ) | (1,851 | ) |
Dividends | (40 | ) | (122 | ) |
EG LNG return of capital and other | 4 |
| 49 |
|
Organic free cash flow (a) | $ | 81 |
| $ | 298 |
|
| |
(a) | Non-GAAP financial measure. See “Non-GAAP Measures” above for further discussion. |
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| | | | | | |
Supplemental Statistics (Unaudited) | Three Months Ended |
| Sept. 30 |
| June 30 |
| Sept. 30 |
|
(mboed) | 2019 |
| 2019 |
| 2018 |
|
Net production | | | |
United States | 339 |
| 332 |
| 304 |
|
International | 87 |
| 103 |
| 115 |
|
Total net production | 426 |
| 435 |
| 419 |
|
|
| | | | | | |
Supplemental Statistics (Unaudited) | Three Months Ended |
| Sept. 30 |
| June 30 |
| Sept. 30 |
|
(mboed) | 2019 |
| 2019 |
| 2018 |
|
Net production | | | |
United States | 339 |
| 332 |
| 304 |
|
Less: Divestitures (a) | 1 |
| 2 |
| 4 |
|
Total divestiture-adjusted United States | 338 |
| 330 |
| 300 |
|
| | | |
International | 87 |
| 103 |
| 115 |
|
Less: Divestitures (b) | — |
| 12 |
| 16 |
|
Total divestiture-adjusted International | 87 |
| 91 |
| 99 |
|
| | | |
Total net production divestiture-adjusted (a)(b) | 425 |
| 421 |
| 399 |
|
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(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 sale of our U.K. business, which closed in third quarter 2019, and the sale of our non-operated interest in Kurdistan, which closed in second quarter 2019. These production volumes have been removed from historical periods above in arriving at total divestiture-adjusted International net production. |
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| | | | | | |
Supplemental Statistics (Unaudited) | Three Months Ended |
| Sept. 30 |
| June 30 |
| Sept. 30 |
|
| 2019 |
| 2019 |
| 2018 |
|
United States - net sales volumes | | | |
Crude oil and condensate (mbbld) | 201 |
| 190 |
| 173 |
|
Eagle Ford | 63 |
| 61 |
| 66 |
|
Bakken | 92 |
| 88 |
| 72 |
|
Oklahoma | 23 |
| 21 |
| 18 |
|
Northern Delaware | 18 |
| 15 |
| 12 |
|
Other United States | 5 |
| 5 |
| 5 |
|
Natural gas liquids (mbbld) | 61 |
| 64 |
| 58 |
|
Eagle Ford | 22 |
| 25 |
| 26 |
|
Bakken | 9 |
| 8 |
| 6 |
|
Oklahoma | 23 |
| 24 |
| 21 |
|
Northern Delaware | 6 |
| 6 |
| 4 |
|
Other United States | 1 |
| 1 |
| 1 |
|
Natural gas (mmcfd) | 462 |
| 459 |
| 433 |
|
Eagle Ford | 134 |
| 139 |
| 137 |
|
Bakken | 46 |
| 42 |
| 36 |
|
Oklahoma | 229 |
| 223 |
| 208 |
|
Northern Delaware | 36 |
| 36 |
| 30 |
|
Other United States | 17 |
| 19 |
| 22 |
|
Total United States (mboed) | 339 |
| 330 |
| 303 |
|
International - net sales volumes | | | |
Crude oil and condensate (mbbld) | 16 |
| 30 |
| 27 |
|
Equatorial Guinea | 16 |
| 20 |
| 18 |
|
United Kingdom | — |
| 8 |
| 6 |
|
Other International | — |
| 2 |
| 3 |
|
Natural gas liquids (mbbld) | 10 |
| 10 |
| 11 |
|
Equatorial Guinea | 10 |
| 10 |
| 11 |
|
United Kingdom | — |
| — |
| — |
|
Natural gas (mmcfd) | 373 |
| 403 |
| 441 |
|
Equatorial Guinea | 373 |
| 392 |
| 426 |
|
United Kingdom (a) | — |
| 11 |
| 15 |
|
Total International (mboed) | 88 |
| 107 |
| 112 |
|
Total Company - net sales volumes (mboed) | 427 |
| 437 |
| 415 |
|
Net sales volumes of equity method investees | | | |
LNG (mtd) | 4,590 |
| 5,321 |
| 6,152 |
|
Methanol (mtd) | 1,036 |
| 1,134 |
| 1,334 |
|
Condensate and LPG (boed) | 11,586 |
| 11,080 |
| 11,942 |
|
| |
(a) | Includes natural gas acquired for injection and subsequent resale. |
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| | | | | | | | | |
Supplemental Statistics (Unaudited) | Three Months Ended |
| Sept. 30 |
| June 30 |
| Sept. 30 |
|
| 2019 |
| 2019 |
| 2018 |
|
United States - average price realizations (a) | | | |
Crude oil and condensate ($ per bbl) (b) | $ | 55.09 |
| $ | 59.18 |
| $ | 68.51 |
|
Eagle Ford | 57.99 |
| 63.10 |
| 72.00 |
|
Bakken | 53.48 |
| 56.84 |
| 67.26 |
|
Oklahoma | 55.09 |
| 58.66 |
| 70.14 |
|
Northern Delaware | 54.16 |
| 55.33 |
| 55.01 |
|
Other United States (c) | 51.74 |
| 66.21 |
| 66.67 |
|
Natural gas liquids ($ per bbl) | $ | 11.37 |
| $ | 14.60 |
| $ | 28.07 |
|
Eagle Ford | 11.40 |
| 13.19 |
| 28.62 |
|
Bakken | 7.16 |
| 18.68 |
| 31.92 |
|
Oklahoma | 13.20 |
| 14.39 |
| 25.29 |
|
Northern Delaware | 10.02 |
| 15.02 |
| 31.44 |
|
Other United States (c) | 15.21 |
| 17.25 |
| 34.71 |
|
Natural gas ($ per mcf) (d) | $ | 1.92 |
| $ | 1.89 |
| $ | 2.55 |
|
Eagle Ford | 2.29 |
| 2.51 |
| 2.84 |
|
Bakken | 1.83 |
| 1.70 |
| 2.64 |
|
Oklahoma | 1.75 |
| 1.78 |
| 2.40 |
|
Northern Delaware | 0.84 |
| 0.18 |
| 2.24 |
|
Other United States (c) | 3.69 |
| 2.26 |
| 2.48 |
|
International - average price realizations | | | |
Crude oil and condensate ($ per bbl) | $ | 46.04 |
| $ | 58.21 |
| $ | 64.08 |
|
Equatorial Guinea | 46.04 |
| 54.38 |
| 61.23 |
|
United Kingdom | — |
| 68.40 |
| 73.28 |
|
Other International | — |
| 55.83 |
| 62.30 |
|
Natural gas liquids ($ per bbl) | $ | 1.00 |
| $ | 1.67 |
| $ | 2.04 |
|
Equatorial Guinea (d) | 1.00 |
| 1.00 |
| 1.00 |
|
United Kingdom | — |
| 37.63 |
| 50.37 |
|
Natural gas ($ per mcf) | $ | 0.24 |
| $ | 0.35 |
| $ | 0.50 |
|
Equatorial Guinea (d) | 0.24 |
| 0.24 |
| 0.24 |
|
United Kingdom | — |
| 4.25 |
| 8.60 |
|
Benchmark | | | |
WTI crude oil (per bbl) | $ | 56.44 |
| $ | 59.91 |
| $ | 69.43 |
|
Brent (Europe) crude oil (per bbl) (e) | $ | 61.93 |
| $ | 68.92 |
| $ | 75.22 |
|
Mont Belvieu NGLs (per bbl) (f) | $ | 15.16 |
| $ | 17.64 |
| $ | 31.25 |
|
Henry Hub natural gas (per mmbtu) (g) | $ | 2.23 |
| $ | 2.64 |
| $ | 2.90 |
|
| |
(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 $0.72, $0.32 and $(5.70) for third quarter 2019, second quarter 2019, and third quarter 2018. |
| |
(c) | Includes sales volumes from the sale of certain non-core proved properties in our International and United States segments. |
| |
(d) | Represents fixed prices under long-term contracts with Alba Plant LLC, Atlantic Methanol Production Company LLC and/or Equatorial Guinea LNG Holdings Limited, which are equity method investees. The Alba Plant LLC processes the NGLs and then sells secondary condensate, propane, and butane at market prices. Marathon Oil includes its share of income from each of these equity method investees in the International segment. |
| |
(e) | Average of monthly prices obtained from Energy Information Administration website. |
| |
(f) | Bloomberg Finance LLP: Y-grade Mix NGL of 55% ethane, 25% propane, 5% butane, 8% isobutane and 7% natural gasoline. |
| |
(g) | Settlement date average per mmbtu. |
|
| | | | | | | | | | | | | | | | | |
Q4 2019 Production Guidance | Oil Production (mbbld) | | Equivalent Production (mboed) |
Q4 2019 | Q3 2019 | Q4 2018 | | Q4 2019 | Q3 2019 | Q4 2018 |
| Low | High | Divestiture-Adjusted | Divestiture-Adjusted | | Low | High | Divestiture-Adjusted | Divestiture-Adjusted |
Net production | | | | | | | | | |
United States | 190 |
| 200 |
| 201 |
| 179 |
| | 320 |
| 330 |
| 338 |
| 304 |
|
International | 12 |
| 16 |
| 15 |
| 16 |
| | 80 |
| 90 |
| 87 |
| 93 |
|
Total net production | 202 |
| 216 |
| 216 |
| 195 |
| | 400 |
| 420 |
| 425 |
| 397 |
|
The following table sets forth outstanding derivative contracts as of Nov. 5, 2019, and the weighted average prices for those contracts: |
| | | | | | | | | | | | | | |
| 2019 | | | 2020 | | | 2021 |
Crude Oil | | Fourth Quarter | | | Full Year | | | Full Year |
NYMEX WTI Three-Way Collars | | | | | | | | |
Volume (Bbls/day) | | 80,000 |
| | | 42,945 |
| | | — |
|
Weighted average price per Bbl: | | | | | | | | |
Ceiling | | $ | 74.19 |
| | | $ | 65.58 |
| | | — |
|
Floor | | $ | 56.75 |
| | | $ | 55.00 |
| | | — |
|
Sold put | | $ | 49.50 |
| | | $ | 47.77 |
| | | — |
|
Basis Swaps - Argus WTI Midland (a) | | | | | | | | |
Volume (Bbls/day) | | 15,000 |
| | | 15,000 |
| | | — |
|
Weighted average price per Bbl | | $ | (1.40 | ) | | | $ | (0.94 | ) | | | — |
|
Basis Swaps - Net Energy Clearbrook (b) | | | | | | | | |
Volume (Bbls/day) | | 2,000 |
| | | — |
| | | — |
|
Weighted average price per Bbl | | $ | (3.33 | ) | | | — |
| | | — |
|
Basis Swaps - NYMEX WTI / ICE Brent (c) | | | | | | | | |
Volume (Bbls/day) | | 5,000 |
| | | 5,000 |
| | | 808 |
|
Weighted average price per Bbl | | $ | (7.24 | ) | | | $ | (7.24 | ) | | | $ | (7.24 | ) |
Basis Swaps - Argus WTI Houston (d) | | | | | | | | |
Volume (Bbls/day) | | 10,000 |
| | | — |
| | | — |
|
Weighted average price per Bbl | | $ | 5.51 |
| | | $ | — |
| | | $ | — |
|
NYMEX Roll Basis Swaps | | | | | | | | |
Volume (Bbls/day) | | 60,000 |
| | | — |
| | | — |
|
Weighted average price per Bbl | | $ | 0.38 |
| | | — |
| | | — |
|
Natural Gas | | | | | | | | |
Three-Way Collars (e) | | | | | | | | |
Volume (MMBtu/day) | | — |
| | | 24,863 |
| | | — |
|
Weighted average price per MMBtu: | | | | | | | | |
Ceiling | | — |
| | | 3.32 |
| | | — |
|
Floor | | — |
| | | 2.75 |
| | | — |
|
Sold put | | — |
| | | 2.25 |
| | | — |
|
| |
(a) | The basis differential price is indexed against Argus WTI Midland. |
| |
(b) | The basis differential price is indexed against Net Energy Canada Bakken SW at Clearbrook (“UHC”). |
| |
(c) | The basis differential price is indexed against International Commodity Exchange (“ICE”) Brent and NYMEX WTI. |
| |
(d) | The basis differential price is indexed against Argus WTI Houston. |
| |
(e) | Between Oct. 1, 2019 and Nov. 5, 2019, we entered into 100,000 MMBtu/day of three-way collars for January - March 2020 with a ceiling price of $3.32, a floor price of $2.75, and a sold put price of $2.25. |