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
impairments and other
|
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
changes in working capital (a)
|
$
|
428
|
|
$
|
352
|
|
$
|
685
|
|
$
|
1,416
|
|
$
|
2,885
|
|
|
|
|
|
|
|
Free Cash
Flow
|
|
|
|
|
|
Net cash provided by
operating activities before changes in
working capital (a)
|
$
|
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
Production Guidance
|
Oil Production
(mbbld)
|
|
Equivalent
Production (mboed)
|
Full Year
2021
|
Q4
2020
|
Full Year
2020
|
|
Full Year
2021
|
Q4
2020
|
Full Year
2020
|
|
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
Quarter
|
|
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