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22.02.2021 22:32:00
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Marathon Oil Announces 2021 Capital Budget and Reports Fourth Quarter and Full Year 2020 Results
HOUSTON, Feb. 22, 2021 /PRNewswire/ -- Marathon Oil Corporation (NYSE:MRO) reported a fourth quarter 2020 net loss of $338 million, or $0.43 per diluted share, which includes the impact of certain items not typically represented in analysts' earnings estimates and that would otherwise affect comparability of results. The adjusted net loss was $98 million, or $0.12 per diluted share. Net operating cash flow was $418 million, or $428 million before changes in working capital.
Marathon Oil reported full year 2020 net loss of $1,451 million, or $1.83 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 loss was $919 million, or $1.16 per diluted share. Net operating cash flow was $1,473 million, or $1,416 million before changes in working capital.
Highlights
- 2021 capital expenditure budget of $1.0 billion consistent with transparent capital allocation framework
- Expected FCF of ~$1 billion at $50/bbl WTI with reinvestment rate of ~50%1
- Expected FCF breakeven below $35/bbl WTI2
- Total Company oil production flat to fourth quarter 2021 exit rate
- Targeting $500 million of gross debt reduction
- 5 Year Benchmark Maintenance Scenario underscores portfolio strength and free cash flow sustainability
- Cumulative potential FCF of ~$5 billion at flat $50/bbl WTI from 2021 to 20253
- Expected FCF breakeven below $35/bbl WTI2 throughout period
- $1.0 to $1.1 billion of capex per year with flat total Company oil production
- Strong fourth quarter and full year 2020 financial and operational results
- Fourth quarter free cash flow of $162 million; full year 2020 free cash flow of $277 million
- Reinstated base dividend in fourth quarter; returned ~$250 million to investors in 2020, including ~$150 million of dividends and share repurchases and $100 million gross debt reduction
- Full year total capital expenditures of $1.16 billion, below guidance of $1.2 billion
- Reduced both production and general and administrative costs by more than 20% vs. prior year
- Fourth quarter and full year total Company oil production of 172,000 net bopd and 190,000 net bopd, both at guidance midpoint
- $3.7 billion of liquidity at year-end, including $3.0 billion undrawn revolving credit facility and $0.7 billion of cash and cash equivalents; investment grade credit rating at all three primary rating agencies
- CEO and Board compensation reduced 25%4 and compensation framework improved to further enhance alignment with investors
- Expect 2020 GHG emissions intensity reduction of approximately 20%5 vs. 2019; improved total Company gas capture to 98.5% for fourth quarter 2020
- Added 2021 GHG emissions intensity target representing an approximate 30% reduction vs. 2019; announced medium-term goal to reduce GHG emissions intensity by at least 50% by 2025 vs. 2019
"While 2020 was a challenging year for our industry, I am proud of our many accomplishments, especially our record setting safety performance as we successfully managed through the ongoing COVID-19 pandemic as critical essential infrastructure providers," said Chairman, President, and CEO Lee Tillman. "In addition, we reduced our cash costs by more than 20%, protected our investment grade balance sheet, reduced our gross debt, meaningfully improved our GHG emissions intensity, and ultimately generated about $280 million of free cash flow.
"For 2021," Tillman continued, "we have set a maintenance capital budget that prioritizes corporate returns and free cash flow generation over production growth. Consistent with our commitment to capital discipline, we won't raise our level of spending even if recent commodity price strength persists. We will simply generate more free cash flow. Our 2021 budget and our newly disclosed 5 Year Benchmark Maintenance Scenario are both evidence of our high quality portfolio, advantaged capital efficiency, and the sustainability of our strong financial performance. We believe we are well positioned to compete effectively with the broader S&P 500, and to continue executing on our transparent capital allocation framework that prioritizes free cash flow generation, balance sheet strength, and return of capital to investors. Further, we have taken important steps to improve alignment between our management team and investors through proactive compensation changes and are committed to continuing to reduce our GHG emissions intensity."
2021 Overview
Marathon Oil today announced a $1.0 billion capital expenditure budget for 2021 designed to deliver strong corporate returns and sustainable free cash flow. Assuming $50/bbl WTI and $3.00/MMBtu Henry Hub, the 2021 program is expected to deliver approximately $1.0 billion of free cash flow at a reinvestment rate of 50%1. If commodity prices remain higher than $50/bbl, the Company plans no deviation from its maintenance capital budget, prioritizing corporate returns, free cash flow, and capital discipline. At $55/bbl WTI, which is below the prevailing forward curve, the 2021 program is expected to deliver over $1.3B of free cash flow6. The 2021 budget is fully consistent with the Company's transparent capital allocation framework, which targets a reinvestment rate of 70% or less assuming $45/bbl WTI, making available 30% or more of cash flow from operations for investor-friendly purposes. The Company expects to continue prioritizing balance sheet enhancement and direct return of capital to investors, including a targeted $500 million gross debt reduction in 2021. The resilience and free cash flow potential of the 2021 budget is underscored by an enterprise free cash flow breakeven below $35/bbl WTI2. Total company oil production for 2021 is expected to be approximately flat with the fourth quarter 2020 exit rate.
5 Year Benchmark Maintenance Capital Scenario
To highlight the strength of Marathon Oil's portfolio and the sustainability of its financial performance, the Company has disclosed a 5 Year Benchmark Maintenance Capital Scenario designed to hold fourth quarter 2020 total Company oil production flat through 2025. This 5 year scenario includes total capital spending of approximately $1.0 billion to $1.1 billion per year and an enterprise free cash flow breakeven below $35/bbl WTI2 throughout the period. Assuming flat $50/bbl WTI oil and $3.00/MMBtu gas, the maintenance scenario would deliver approximately $5.0 billion of cumulative free cash flow at a reinvestment rate of around 50%. Assuming flat $45/bbl WTI oil and $2.50/MMBtu gas, the maintenance scenario would deliver approximately $3.0 billion of cumulative free cash flow at a reinvestment rate well below 70%3. The Benchmark Scenario includes capital allocation across Marathon Oil's multi-basin portfolio and includes approximately $100 million of cumulative investment to assist the Company in achieving its previously disclosed goal to reduce 2025 greenhouse gas (GHG) emissions intensity by at least 50%.
Continued Cash Cost Reduction Initiatives
During 2020, Marathon Oil took aggressive and decisive action in response to a challenging commodity price and business environment, realizing a reduction of over 20% to both production and general and administrative costs in comparison to the prior year. General and administrative costs specifically were down 23% from 2019. Cost saving measures included temporary base salary reductions for the Board and certain corporate officers, as well as employee and contractor workforce reductions.
Consistent with its focus to continually optimize its cost structure, Marathon Oil expects to drive further cash cost reductions in 2021 and beyond. More specifically, the Company has taken additional action in 2021 to achieve an approximate 30% reduction to its combined production and general and administrative costs relative to 2019. The Company expects to realize the majority of these savings on a run-rate basis by the end of 2021. These reductions represent the continuation of a multi-year trend of ongoing cost structure optimization, expected to result in a total reduction to production and general administrative costs of approximately 40% in comparison to 2018. Newly enacted cost saving measures include an expected 25% reduction to CEO and Board compensation, a 10% to 20% compensation reduction for other corporate officers, an employee and contractor workforce reduction to better align organizational capacity with expected future activity levels, and a reduction to aviation, real estate, project, and various other costs.
United States (U.S.)
U.S. production averaged 280,000 net barrels of oil equivalent per day (boed) for fourth quarter 2020. Oil production averaged 159,000 net barrels of oil per day (bopd). U.S. unit production costs were $4.62 per boe for fourth quarter, and $4.42 per boe for the full year. 2020 represented a record year for unit production costs.
During fourth quarter, the Company brought a total of 49 gross Company-operated wells to sales and delivered an average completed well cost per lateral foot reduction of more than 35% in comparison to the 2019 average. This significant reduction was driven by a combination of optimized capital allocation to the Company's lowest cost Basins, continued strong execution performance, and longer average lateral lengths across the Company's portfolio.
In the Eagle Ford, Marathon Oil's fourth quarter 2020 production averaged 82,000 net boed. Oil production averaged 51,000 net bopd on 20 gross Company-operated wells to sales. In the Bakken, production averaged 110,000 net boed, including oil production of 78,000 net bopd. The Company brought 23 gross Company-operated wells to sales during fourth quarter in the Bakken. Oklahoma production averaged 58,000 net boed in the fourth quarter 2020, including oil production of 15,000 net bopd. Northern Delaware production averaged 21,000 net boed in the fourth quarter 2020, while oil production averaged 12,000 net bopd on 6 gross Company-operated wells to sales.
International
Equatorial Guinea production averaged 72,000 net boed for fourth quarter 2020, including 13,000 net bopd of oil. Unit production costs averaged $2.49 per boe during fourth quarter and $2.12 per boe for the full year 2020. Full year unit production costs represented a record low for the International segment. First gas was recently achieved from the 3rd party Alen project in February. Marathon Oil's equity method investees will process the Alen gas under a combination of a tolling and profit-sharing agreement, the benefits of which will be included in the Company's share of net income from equity method investees.
Assuming $50/WTI and $3/MMBtu Henry Hub, the Company's total equity method net income in 2021 is expected to range from $100 million to $120 million, inclusive of Alen contributions. Marathon Oil's equity income excludes financial contributions from the Alba gas and condensate field under its production sharing contract, the results of which are consolidated in the Company's financial statements.
Corporate
Net cash provided by operations was $418 million during fourth quarter 2020, or $428 million before changes in working capital. Fourth quarter capital expenditures totaled $270 million, bringing full year 2020 total capital expenditures to $1.16 billion, below Company guidance of $1.2 billion.
Total liquidity as of December 31 was approximately $3.7 billion, which consisted of an undrawn revolving credit facility of $3.0 billion and $0.7 billion in cash and cash equivalents. The Company continues to maintain an investment grade credit rating at all three primary rating agencies.
During the fourth quarter, Marathon Oil reinstated a quarterly dividend at 3 cents per share and completed a cash tender for an aggregate principal amount of $500 million of its then outstanding $1 billion 2.8% Senior Notes due November 2022. The tender resulted in a $100 million gross debt reduction for the year and reduced the Company's next significant debt maturity by half.
Year-end 2020 proved reserves totaled 972 million barrels of oil equivalent (mmboe), with reductions attributable to 2020 production, decreased activity in the 5-year plan, and lower commodity prices, partially offset by cost reductions and performance improvements. Oil accounts for 52% of the Company's year-end 2020 proved reserves.
The adjustments to net loss for fourth quarter 2020 totaled $240 million, primarily due to the income impact associated with exploration and unproved property impairments, unrealized losses on derivative instruments, loss on debt extinguishment, and other non-core expenses.
Governance
Marathon Oil is fully committed to best-in-class corporate governance as its foundation for executing its long-term strategy. As announced in January, the Company has reduced executive compensation and modified its framework to enhance alignment with shareholders, incentivize achievement of its core strategic objectives, and encourage the behaviors the Company believes are most likely to maximize long-term shareholder value.
More specifically, the Company is reducing annual Board of Director compensation by 25% with the compensation mix shifted more toward equity. The Company is also reducing CEO total direct compensation by 25%, including a 35% reduction to long-term incentive (LTI) awards. These changes are intended to better align CEO compensation quantum and mix with the broader industry and current business environment.
Marathon Oil's short-term incentive (STI) annual cash bonus scorecard has been restructured to better reflect the Company's financial and ESG framework, with all production and growth metrics removed. Additionally, the Company has revised its LTI compensation framework to mitigate overreliance on relative TSR against direct E&P peers, adding S&P 500 and S&P Energy indices as peer comparators, and has introduced free cash flow as an additional LTI performance metric.
Safety and Environmental
Marathon Oil views safety as a core value and a key component of its ESG performance. Keeping its workforce safe, both employees and contractors, is and always will be a top priority. During 2020, the Company successfully managed through the ongoing COVID-19 pandemic with record setting safety performance, as measured by a total recordable incident rate (TRIR) of 0.247. This was Marathon Oil's second consecutive year of record TRIR performance. Peer leading safety performance will remain a component of the Company's executive compensation scorecard.
Reducing greenhouse gas (GHG) emissions intensity is central to Marathon Oil's strategic goals of minimizing its environmental impact, addressing the risks of climate change, and delivering strong long-term financial performance.
During 2020 the Company made significant progress in improving its environmental performance, achieving an estimated 20% reduction to its GHG emissions intensity relative to 2019 and improving total Company gas capture to approximately 98.5% for fourth quarter 2020.
For 2021, the Company has established a quantitative GHG intensity target, representing a reduction of more than 30% relative to 2019, which has been added to the Company's executive compensation scorecard. Further, Marathon Oil has disclosed a new medium-term goal highlighting the Company's commitment to significant ongoing improvement to its environmental performance. By 2025, the Company's goal is to reduce its GHG intensity by at least 50% relative to 2019.
Methodology and definitions for GHG emissions and safety performance are based on information from the Company's 2019 Sustainability Report that can be found on the Company's website. The Company reports direct (Scope 1) and indirect (Scope 2) GHG emissions, with emissions intensity measured by metric tonnes carbon dioxide equivalent (CO2e) emissions per thousand barrels of oil equivalent hydrocarbons produced from Marathon Oil-operated facilities.
A slide deck and Quarterly Investor Packet will be posted to the Company's website following this release today, February 22. On Tuesday, February 23, at 10:00 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://ir.marathonoil.com/.
Footnotes:
1 | $1.0B of expected 2021 FCF at $50/bbl WTI and $3.00/MMBtu comprised of approximately $2.0B of net cash provided by operating activities adjusted for working capital, EG LNG return of capital, and other less approximately $1.0B of capital expenditures; $1.0B of capital expenditures divided by approximately $2.0B of net cash provided by operating activities adjusting for working capital, EG LNG return of capital and other equates to a reinvestment rate of approximately 50% |
2 | $35/bbl WTI breakeven represents WTI benchmark oil price required for cash flow from operations to fully cover capital expenditures, before dividends |
3 | Cumulative FCF of approximately $3B for 5 Year Benchmark Scenario at flat $45/bbl WTI and $2.50/MMBtu comprised of approximately $8.0-8.5B of cumulative net cash provided by operating activities adjusted for working capital, EG LNG return of capital, and other less approximately $5.0-5.5B of cumulative capital expenditures – dividing cumulative capital expenditures by the sum of cumulative net cash provided by operating activities adjusted for working capital, EG LNG return of capital, and other is expected to equate to a reinvestment rate of less than 70%; Cumulative FCF of approximately $5.0B for 5 Year Benchmark Scenario at flat $50/bbl WTI and $3.00/MMBtu comprised of approximately $10.0-10.5B of cumulative net cash provided by operating activities adjusted for working capital, EG LNG return of capital, and other less approximately $5.0-5.5B of cumulative capital expenditures – dividing cumulative capital expenditures by the sum of cumulative net cash provided by operating activities adjusted for working capital, EG LNG return of capital, and other is expected to equate to a reinvestment rate of approximately 50% |
4 | Exclusive of temporary reductions announced in 2020 |
5 | Preliminary estimate subject to final calculation |
6 | $1.3B of expected 2021 FCF at $55/bbl WTI and $3.00/MMBtu; comprised of approximately $2.3B of net cash provided by operating activities adjusted for working capital, EG LNG return of capital, and other less approximately $1.0B of capital expenditures |
7 | Total recordable incident rate (TRIR) measures combined employee and contractor workforce incidents per 200,000 work hours |
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), adjusted net income (loss) per share, free cash flow, net cash provided by operations before changes in working capital, total capital expenditures and capital reinvestment rate.
Our presentation of adjusted net income (loss) and adjusted net income (loss) per share is a non-GAAP measure. Adjusted net income (loss) is defined as net income (loss) adjusted for gains/losses on dispositions, impairments of proved and certain unproved properties, goodwill and equity method investments, certain exploration expenses relating to a strategic decision to exit conventional exploration, unrealized derivative gain/loss on commodity and interest rate derivative instruments, effects of pension settlements and curtailments and other items that could be considered "non-operating" or "non-core" in nature. Management believes this is useful to investors as another tool to meaningfully represent our operating performance and to compare Marathon to certain competitors. Adjusted net income (loss) and adjusted net income (loss) per share should not be considered in isolation or as an alternative to, or more meaningful than, net income (loss) or net income (loss) per share as determined in accordance with U.S. GAAP.
Our presentation of free cash flow is a non-GAAP measure. Free cash flow before dividend ("free cash flow") is defined as net cash provided by operating activities adjusted for working capital, exploration costs (other than well costs), capital expenditures, and EG LNG return of capital and other. Management believes this is useful to investors as a measure of Marathon's ability to fund its capital expenditure programs, service debt, and other distributions to stockholders. Free cash flow should not be considered in isolation or as an alternative to, or more meaningful than, net cash provided by operating activities as determined in accordance with U.S. GAAP.
Our presentation of net cash provided by operations before changes in operating working capital and net cash provided by operations before changes in operating working capital and exploration costs are non-GAAP measures. Management believes this is useful to investors as an indicator of Marathon's ability to generate cash quarterly or year-to-date by eliminating differences caused by the timing of certain working capital items. Net cash provided by operations before changes in working capital and net cash provided by operations before changes in working capital and exploration costs should not be considered in isolation or as an alternative to, or more meaningful than, net cash provided by operating activities as determined in accordance with U.S. GAAP.
Our presentation of total capital expenditures is a non-GAAP measure. Total capital expenditures is defined as cash additions to property, plant and equipment adjusted for the change in working capital associated with property, plant and equipment, exploration costs other than well costs, M&S inventory and other, and additions to other assets. Management believes this is useful to investors as an indicator of Marathon's commitment to capital expenditure discipline by eliminating differences caused by the timing of certain working capital and other items. Total capital expenditures should not be considered in isolation or as an alternative to, or more meaningful than, cash additions to property, plant and equipment as determined in accordance with U.S. GAAP.
Capital spending reinvestment rate is defined as total capital expenditures divided by operating cash flow before working capital. Management believes the capital spending reinvestment rate is useful to investors to demonstrate the Company's commitment to generating cash for use towards investor friendly purposes (which includes balance sheet enhancement, base dividend, and other return of capital).
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 an alternative 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 https://ir.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, future performance, expected free cash flow, emission targets and estimated emission reductions, future debt reduction, reinvestment rates, corporate-level cash returns on invested capital, business strategy, asset quality, drilling plans, production guidance, cash margins, cost reductions, 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," "future," "guidance," "intend," "may," "outlook," "plan," "positioned," "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 for crude oil and condensate, NGLs and natural gas and the resulting impact on price; changes in expected reserve or production levels; changes in political or economic conditions in the U.S. and Equatorial Guinea, including changes in foreign currency exchange rates, interest rates, inflation rates; actions taken by the members of the Organization of the Petroleum Exporting Countries (OPEC) and Russia affecting the production and pricing of crude oil; and other global and domestic political, economic or diplomatic developments; capital available for exploration and development; risks related to the Company's hedging activities; voluntary or involuntary curtailments, delays or cancellations of certain drilling activities; well production timing; liability resulting from litigation; drilling and operating risks; lack of, or disruption in, access to storage capacity, pipelines or other transportation methods; 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, a health pandemic (including COVID-19), 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, air emissions, or water management; other geological, operating and economic considerations; and the risk factors, forward-looking statements and challenges and uncertainties described in the Company's 2019 Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and other public filings and press releases, available at https://ir.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:
Stephanie Gentry: 713-296-3307
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) | 2020 | 2020 | 2019 | 2020 | 2019 | ||||||||||
Revenues and other income: | |||||||||||||||
Revenues from contracts with customers | $ | 822 | $ | 761 | $ | 1,233 | $ | 3,097 | $ | 5,063 | |||||
Net gain (loss) on commodity derivatives | (15) | (1) | (44) | 116 | (72) | ||||||||||
Income (loss) from equity method investments | 13 | (10) | 24 | (161) | 87 | ||||||||||
Net gain (loss) on disposal of assets | 1 | 1 | (6) | 9 | 50 | ||||||||||
Other income | 9 | 3 | 8 | 25 | 62 | ||||||||||
Total revenues and other income | 830 | 754 | 1,215 | 3,086 | 5,190 | ||||||||||
Costs and expenses: | |||||||||||||||
Production | 137 | 129 | 169 | 555 | 712 | ||||||||||
Shipping, handling and other operating | 164 | 183 | 143 | 596 | 605 | ||||||||||
Exploration | 100 | 27 | 42 | 181 | 149 | ||||||||||
Depreciation, depletion and amortization | 521 | 554 | 616 | 2,316 | 2,397 | ||||||||||
Impairments | 46 | 1 | — | 144 | 24 | ||||||||||
Taxes other than income | 55 | 49 | 79 | 200 | 311 | ||||||||||
General and administrative | 57 | 53 | 93 | 274 | 356 | ||||||||||
Total costs and expenses | 1,080 | 996 | 1,142 | 4,266 | 4,554 | ||||||||||
Income (loss) from operations | (250) | (242) | 73 | (1,180) | 636 | ||||||||||
Net interest and other | (61) | (62) | (67) | (256) | (244) | ||||||||||
Other net periodic benefit (costs) credits | (2) | (6) | (6) | (1) | 3 | ||||||||||
Loss on early extinguishment of debt | (28) | — | (3) | (28) | (3) | ||||||||||
Income (loss) before income taxes | (341) | (310) | (3) | (1,465) | 392 | ||||||||||
Provision (benefit) for income taxes | (3) | 7 | 17 | (14) | (88) | ||||||||||
Net income (loss) | $ | (338) | $ | (317) | $ | (20) | $ | (1,451) | $ | 480 | |||||
Adjusted Net Income (Loss) | |||||||||||||||
Net income (loss) | $ | (338) | $ | (317) | $ | (20) | $ | (1,451) | $ | 480 | |||||
Adjustments for special items (pre-tax): | |||||||||||||||
Net (gain) loss on disposal of assets | (1) | (1) | 6 | (9) | (50) | ||||||||||
Proved property impairments | 46 | 1 | — | 49 | 24 | ||||||||||
Exploratory dry well costs, unproved property | 78 | 6 | — | 84 | — | ||||||||||
Goodwill impairment | — | — | — | 95 | — | ||||||||||
Pension settlement | 5 | 9 | 10 | 30 | 12 | ||||||||||
Pension curtailment | — | — | — | (17) | — | ||||||||||
Unrealized loss on derivative instruments | 66 | 36 | 55 | 27 | 124 | ||||||||||
Reduction in workforce | 2 | 2 | — | 17 | — | ||||||||||
Impairment of equity method investment | 1 | 18 | — | 171 | — | ||||||||||
Loss on early extinguishment of debt | 28 | — | — | 28 | — | ||||||||||
Other | 15 | 28 | 4 | 58 | 28 | ||||||||||
Benefit for income taxes related to special items | — | (1) | — | (1) | (7) | ||||||||||
Adjustments for special items | 240 | 98 | 75 | 532 | 131 | ||||||||||
Adjusted net income (loss) (a) | $ | (98) | $ | (219) | $ | 55 | $ | (919) | $ | 611 | |||||
Per diluted share: | |||||||||||||||
Net income (loss) | $ | (0.43) | $ | (0.40) | $ | (0.03) | $ | (1.83) | $ | 0.59 | |||||
Adjusted net income (loss) (a) | $ | (0.12) | $ | (0.28) | $ | 0.07 | $ | (1.16) | $ | 0.75 | |||||
Weighted average diluted shares | 790 | 790 | 800 | 792 | 810 | ||||||||||
(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) | 2020 | 2020 | 2019 | 2020 | 2019 | ||||||||||
Segment income (loss) | |||||||||||||||
United States | $ | (33) | $ | (135) | $ | 148 | $ | (553) | $ | 675 | |||||
International | 29 | 8 | 33 | 30 | 233 | ||||||||||
Not allocated to segments | (334) | (190) | (201) | (928) | (428) | ||||||||||
Net income (loss) | $ | (338) | $ | (317) | $ | (20) | $ | (1,451) | $ | 480 | |||||
Cash flows | |||||||||||||||
Net cash provided by operating activities | $ | 418 | $ | 345 | $ | 700 | $ | 1,473 | $ | 2,749 | |||||
Changes in working capital | 10 | 7 | (15) | (57) | 136 | ||||||||||
Net cash provided by operating activities before | $ | 428 | $ | 352 | $ | 685 | $ | 1,416 | $ | 2,885 | |||||
Free Cash Flow | |||||||||||||||
Net cash provided by operating activities before changes in | $ | 428 | $ | 352 | $ | 685 | $ | 1,416 | $ | 2,885 | |||||
Adjustments for free cash flow: | |||||||||||||||
Exploration costs other than well costs | 4 | 4 | 13 | 22 | 35 | ||||||||||
Capital expenditures | (270) | (176) | (724) | (1,162) | (2,684) | ||||||||||
EG LNG return of capital and other | — | — | 9 | 1 | 58 | ||||||||||
Free cash flow (a) | $ | 162 | $ | 180 | $ | (17) | $ | 277 | $ | 294 | |||||
Capital Expenditures | |||||||||||||||
Cash additions to property, plant and equipment | $ | (253) | $ | (144) | $ | (616) | $ | (1,343) | $ | (2,550) | |||||
Change in working capital associated with PP&E | (14) | (33) | 15 | 192 | (41) | ||||||||||
Exploration costs other than well costs | (4) | (4) | (13) | (22) | (35) | ||||||||||
M&S inventory and other | 1 | 2 | 1 | (4) | 12 | ||||||||||
Additions to other assets and acquisitions | — | 3 | (111) | 15 | (70) | ||||||||||
Total capital expenditures (a) | $ | (270) | $ | (176) | $ | (724) | $ | (1,162) | $ | (2,684) | |||||
(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 | ||||||
Net Production | 2020 | 2020 | 2019 | 2020 | 2019 | |||||
Equivalent Production (mboed) | ||||||||||
United States | 280 | 297 | 328 | 306 | 324 | |||||
International | 72 | 73 | 85 | 77 | 92 | |||||
Total net production | 352 | 370 | 413 | 383 | 416 | |||||
Less: Divestitures (a) | — | — | — | — | 8 | |||||
Total divestiture-adjusted net production | 352 | 370 | 413 | 383 | 408 | |||||
Oil Production (mbbld) | ||||||||||
United States | 159 | 159 | 196 | 177 | 191 | |||||
International | 13 | 13 | 15 | 13 | 21 | |||||
Total net production | 172 | 172 | 211 | 190 | 212 | |||||
Less: Divestitures (b) | — | — | — | — | 6 | |||||
Total divestiture-adjusted net production | 172 | 172 | 211 | 190 | 206 | |||||
(a) | Divestitures for the year ended 2019 include the following: (i) 1 mboed related to the sale of certain United States non-core conventional assets which closed in first quarter 2019 (ii) 6 mboed related to the sale of our U.K. business which closed in third quarter 2019 and (iii) 1 mboed related to the sale of our non-operated interest in the Atrush block in Kurdistan which closed in second quarter 2019. |
(b) | Divestitures for the year ended 2019 include 5 mbbld related to the sale of our U.K. business which closed in third quarter 2019 and 1 mbbld related to the sale of our non-operated interest in the Atrush block in Kurdistan which closed in second quarter 2019. |
Supplemental Statistics (Unaudited) | Three Months Ended | Year Ended | ||||||||
Dec. 31 | Sept. 30 | Dec. 31 | Dec. 31 | Dec. 31 | ||||||
2020 | 2020 | 2019 | 2020 | 2019 | ||||||
United States - net sales volumes | ||||||||||
Crude oil and condensate (mbbld) | 159 | 159 | 196 | 177 | 190 | |||||
Eagle Ford | 51 | 53 | 67 | 61 | 63 | |||||
Bakken | 78 | 69 | 86 | 79 | 86 | |||||
Oklahoma | 15 | 18 | 24 | 17 | 21 | |||||
Northern Delaware | 11 | 15 | 16 | 15 | 16 | |||||
Other United States (a) | 4 | 4 | 3 | 5 | 4 | |||||
Natural gas liquids (mbbld) | 54 | 68 | 58 | 59 | 60 | |||||
Eagle Ford | 14 | 20 | 18 | 18 | 22 | |||||
Bakken | 18 | 16 | 12 | 14 | 9 | |||||
Oklahoma | 17 | 25 | 22 | 20 | 22 | |||||
Northern Delaware | 4 | 5 | 5 | 5 | 6 | |||||
Other United States (a) | 1 | 2 | 1 | 2 | 1 | |||||
Natural gas (mmcfd) | 402 | 421 | 444 | 423 | 438 | |||||
Eagle Ford | 103 | 111 | 121 | 121 | 130 | |||||
Bakken | 86 | 76 | 59 | 70 | 46 | |||||
Oklahoma | 164 | 179 | 216 | 177 | 210 | |||||
Northern Delaware | 34 | 40 | 41 | 41 | 36 | |||||
Other United States (a) | 15 | 15 | 7 | 14 | 16 | |||||
Total United States (mboed) | 280 | 297 | 328 | 306 | 323 | |||||
International - net sales volumes | ||||||||||
Crude oil and condensate (mbbld) | 14 | 11 | 13 | 13 | 20 | |||||
Equatorial Guinea | 14 | 11 | 13 | 13 | 15 | |||||
United Kingdom (b) | — | — | — | — | 4 | |||||
Other International (c) | — | — | — | — | 1 | |||||
Natural gas liquids (mbbld) | 8 | 8 | 9 | 9 | 9 | |||||
Equatorial Guinea | 8 | 8 | 9 | 9 | 9 | |||||
Natural gas (mmcfd) | 306 | 310 | 363 | 330 | 371 | |||||
Equatorial Guinea | 306 | 310 | 363 | 330 | 365 | |||||
United Kingdom (b)(d) | — | — | — | — | 6 | |||||
Total International (mboed) | 73 | 71 | 83 | 77 | 91 | |||||
Total Company - net sales volumes (mboed) | 353 | 368 | 411 | 383 | 414 | |||||
Net sales volumes of equity method investees | ||||||||||
LNG (mtd) | 3,510 | 3,960 | 5,180 | 4,289 | 4,933 | |||||
Methanol (mtd) | 1,080 | 1,065 | 1,153 | 1,017 | 1,082 | |||||
Condensate and LPG (boed) | 10,288 | 9,340 | 11,832 | 10,288 | 11,104 | |||||
(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) | Other International includes volumes for the Atrush block in Kurdistan, which was sold in the second quarter of 2019. |
(d) | 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 | |||||||||||
2020 | 2020 | 2019 | 2020 | 2019 | |||||||||||
United States - average price realizations (a) | |||||||||||||||
Crude oil and condensate ($ per bbl) (b) | $ | 39.71 | $ | 37.78 | $ | 54.83 | $ | 35.93 | $ | 55.80 | |||||
Eagle Ford | 40.69 | 38.79 | 57.63 | 37.42 | 59.06 | ||||||||||
Bakken | 38.66 | 36.28 | 51.98 | 34.09 | 53.65 | ||||||||||
Oklahoma | 40.43 | 38.49 | 55.49 | 37.04 | 55.78 | ||||||||||
Northern Delaware | 41.49 | 40.18 | 57.08 | 37.50 | 54.04 | ||||||||||
Other United States (c) | 40.08 | 38.51 | 56.26 | 38.37 | 57.47 | ||||||||||
Natural gas liquids ($ per bbl) | $ | 16.30 | $ | 11.80 | $ | 15.47 | $ | 11.28 | $ | 14.22 | |||||
Eagle Ford | 16.34 | 12.07 | 15.72 | 11.32 | 14.27 | ||||||||||
Bakken | 15.66 | 10.26 | 13.12 | 9.91 | 13.48 | ||||||||||
Oklahoma | 17.46 | 12.15 | 17.30 | 12.42 | 14.66 | ||||||||||
Northern Delaware | 14.77 | 13.65 | 12.35 | 10.36 | 13.15 | ||||||||||
Other United States (c) | 15.10 | 12.17 | 13.98 | 12.27 | 16.43 | ||||||||||
Natural gas ($ per mcf) | $ | 2.31 | $ | 1.78 | $ | 2.10 | $ | 1.77 | $ | 2.18 | |||||
Eagle Ford | 2.55 | 1.79 | 2.40 | 1.94 | 2.54 | ||||||||||
Bakken | 1.49 | 1.26 | 2.31 | 1.32 | 2.34 | ||||||||||
Oklahoma | 2.72 | 2.03 | 1.95 | 1.97 | 2.04 | ||||||||||
Northern Delaware | 1.75 | 1.53 | 1.72 | 1.20 | 1.17 | ||||||||||
Other United States (c) | 2.02 | 1.90 | 1.89 | 1.84 | 2.81 | ||||||||||
International - average price realizations | |||||||||||||||
Crude oil and condensate ($ per bbl) | $ | 35.08 | $ | 30.28 | $ | 48.26 | $ | 28.36 | $ | 53.09 | |||||
Equatorial Guinea | 35.08 | 30.28 | 48.26 | 28.36 | 48.99 | ||||||||||
United Kingdom (d) | — | — | — | — | 67.99 | ||||||||||
Other International (e) | — | — | — | — | 51.24 | ||||||||||
Natural gas liquids ($ per bbl) | $ | 1.00 | $ | 1.00 | $ | 1.00 | $ | 1.00 | $ | 1.40 | |||||
Equatorial Guinea (f) | 1.00 | 1.00 | 1.00 | 1.00 | 1.00 | ||||||||||
United Kingdom (d) | — | — | — | — | 37.88 | ||||||||||
Natural gas ($ per mcf) | $ | 0.24 | $ | 0.24 | $ | 0.24 | $ | 0.24 | $ | 0.33 | |||||
Equatorial Guinea (f) | 0.24 | 0.24 | 0.24 | 0.24 | 0.24 | ||||||||||
United Kingdom (d) | — | — | — | — | 5.67 | ||||||||||
Benchmark | |||||||||||||||
WTI crude oil (per bbl) | $ | 42.70 | $ | 40.92 | $ | 56.87 | $ | 39.34 | $ | 57.04 | |||||
Brent (Europe) crude oil (per bbl) (g) | $ | 44.29 | $ | 42.96 | $ | 63.41 | $ | 41.76 | $ | 64.36 | |||||
Mont Belvieu NGLs (per bbl) (h) | $ | 17.42 | $ | 15.87 | $ | 17.15 | $ | 14.69 | $ | 17.81 | |||||
Henry Hub natural gas (per mmbtu) (i) | $ | 2.66 | $ | 1.98 | $ | 2.50 | $ | 2.08 | $ | 2.63 | |||||
(a) | Excludes gains or losses on commodity derivative instruments. |
(b) | Inclusion of realized gains (losses) on crude oil derivative instruments would have increased average price realizations by $3.52, $2.24, $0.58, $2.14 and $0.67 for the fourth quarter 2020, the third quarter 2020, the fourth quarter 2019, and the years 2020 and 2019, 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) | Other International includes volumes for the Atrush block in Kurdistan, which was sold in the second quarter of 2019. |
(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 segment. |
(g) | Average of monthly prices obtained from Energy Information Administration website. |
(h) | Bloomberg Finance LLP: Y-grade Mix NGL of 55% ethane, 25% propane, 5% butane, 8% isobutane and 7% natural gasoline. |
(i) | Settlement date average per mmbtu. |
Full Year 2021 | Oil Production (mbbld) | Equivalent Production (mboed) | |||||||
Full Year | Q4 | Full Year | Full Year | Q4 | Full Year | ||||
Low | High | Divestiture-Adjusted | Low | High | Divestiture-Adjusted | ||||
Net production | |||||||||
United States | 158 | 162 | 159 | 177 | 270 | 280 | 280 | 306 | |
International | 11 | 13 | 13 | 13 | 60 | 70 | 72 | 77 | |
Total net production | 169 | 175 | 172 | 190 | 330 | 350 | 352 | 383 | |
The following table sets forth outstanding derivative contracts as of February 15, 2021, and the weighted average prices for those contracts:
2021 | |||||||||||||||||
First Quarter | Second | Third Quarter | Fourth Quarter | ||||||||||||||
Crude Oil | |||||||||||||||||
NYMEX WTI Three-Way Collars | |||||||||||||||||
Volume (Bbls/day) | — | 40,000 | 10,000 | — | |||||||||||||
Weighted average price per Bbl: | |||||||||||||||||
Ceiling | $ | — | $ | 61.46 | $ | 65.18 | $ | — | |||||||||
Floor | $ | — | $ | 39.75 | $ | 45.00 | $ | — | |||||||||
Sold put | $ | — | $ | 29.75 | $ | 35.00 | $ | — | |||||||||
NYMEX WTI Two-Way Collars | |||||||||||||||||
Volume (Bbls/day) | 90,000 | 50,000 | 30,000 | 30,000 | |||||||||||||
Weighted average price per Bbl: | |||||||||||||||||
Ceiling | $ | 51.86 | $ | 52.98 | $ | 51.54 | $ | 51.54 | |||||||||
Floor | $ | 35.44 | $ | 35.80 | $ | 35.67 | $ | 35.67 | |||||||||
Fixed Price WTI Swaps | |||||||||||||||||
Volume (Bbls/day) | 20,000 | — | — | — | |||||||||||||
Weighted average price per Bbl | $ | 50.35 | $ | — | $ | — | $ | — | |||||||||
Basis Swaps - NYMEX WTI / ICE Brent (a) | |||||||||||||||||
Volume (Bbls/day) | 3,278 | — | — | — | |||||||||||||
Weighted average price per Bbl | $ | (7.24) | $ | — | $ | — | $ | — | |||||||||
Basis Swaps - NYMEX WTI / UHC (b) | |||||||||||||||||
Volume (Bbls/day) | 14,344 | 15,000 | — | — | |||||||||||||
Weighted average price per Bbl | $ | (1.80) | $ | (1.80) | $ | — | $ | — | |||||||||
NYMEX Roll Basis Swaps | |||||||||||||||||
Volume (Bbls/day) | 50,000 | 50,000 | — | — | |||||||||||||
Weighted average price per Bbl | $ | (0.13) | $ | (0.13) | $ | — | $ | — | |||||||||
Natural Gas | |||||||||||||||||
Henry Hub ("HH") Two-Way Collars | |||||||||||||||||
Volume (MMBtu/day) | 250,000 | 200,000 | 200,000 | 200,000 | |||||||||||||
Weighted average price per MMBtu: | |||||||||||||||||
Ceiling | $ | 3.14 | $ | 3.05 | $ | 3.05 | $ | 3.05 | |||||||||
Floor | $ | 2.52 | $ | 2.50 | $ | 2.50 | $ | 2.50 | |||||||||
HH Fixed Price Swaps | |||||||||||||||||
Volume (MMBtu/day) | 50,000 | 50,000 | 50,000 | 50,000 | |||||||||||||
Weighted average price per MMBtu | $ | 2.88 | $ | 2.88 | $ | 2.88 | $ | 2.88 | |||||||||
NGL | |||||||||||||||||
Fixed Price Propane Swaps (c) | |||||||||||||||||
Volume (Bbls/day) | 5,000 | 5,000 | 5,000 | 5,000 | |||||||||||||
Weighted average price per Bbl | $ | 23.19 | $ | 23.19 | $ | 23.19 | $ | 23.19 | |||||||||
(a) | The basis differential price is indexed against Intercontinental Exchange ("ICE") Brent and NYMEX WTI. |
(b) | The basis differential price is indexed against U.S. Sweet Clearbrook ("UHC") and NYMEX WTI. |
(c) | The fixed price propane swap is priced at Mont Belvieu Spot Gas Liquids Prices: Non-TET Propane. |
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SOURCE Marathon Oil Corporation
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