MARATHON OIL : Management's Discussion and Analysis of Financial Condition and Results of Operations (form 10-K)

February 23, 2021 at 04:15 pm EST

The following discussion and analysis of our financial condition and results of
operations should be read in conjunction with the information under Item 8.
Financial Statements and Supplementary Data and the other financial information
found elsewhere in this Form 10-K. The following discussion includes
forward-looking statements that involve certain risks and uncertainties. See
"Disclosures Regarding Forward-Looking Statements" (immediately prior to Part I)
and   Item 1A. Risk Factors  .
Each of our two reportable operating segments are organized by geographic
location and managed according to the nature of the products and services
offered.
•United States - explores for, produces and markets crude oil and condensate,
NGLs and natural gas in the United States;
•International - explores for, produces and markets crude oil and condensate,
NGLs and natural gas outside of the United States and produces and markets
products manufactured from natural gas, such as LNG and methanol, in E.G.
Executive Overview
We are an independent exploration and production company based in Houston,
Texas. Our strategy is to deliver competitive and improving corporate level
returns and sustainable free cash flow through disciplined investment across our
U.S. resource plays (the Eagle Ford in Texas, the Bakken in North Dakota, STACK
and SCOOP in Oklahoma and Northern Delaware in New Mexico). Our reinvestment
rate capital allocation framework prioritizes free cash flow generation across a
wide range of commodity prices to make available significant cash flow for
investor-friendly purposes, including return of capital to shareholders and
balance sheet enhancement. Protecting our balance sheet, keeping our workforce
safe, minimizing our environmental impact and strong corporate governance are
foundational to the execution of our strategy.
The risks associated with COVID-19 impacted our workforce and the way we meet
our business objectives. Due to concerns over health and safety, the vast
majority of our corporate workforce works remotely for at least a portion of the
time. We have begun a process for a phased return of employees to the office.
Working remotely has not significantly impacted our ability to maintain
operations, has allowed our field offices to operate without any disruption, and
has not caused us to incur significant additional expenses; however, we are
unable to predict the duration or ultimate impact of these measures.
Key 2020 highlights include:
Reducing and optimizing our Capital Budget
•In February 2020, we announced an approved 2020 Capital Budget of $2.4 billion,
including $200 million to fund REx. Given the substantial decline in commodity
prices and oversupply in the market, our Board of Directors approved two
separate reductions, culminating in a revised Capital Budget of $1.2 billion.
The revised budget contemplated a full suspension of our Oklahoma activity in
2020, a decrease in Northern Delaware and REx drilling programs, and
optimization of our development plans in the Bakken and Eagle Ford.
Maintained focus on balance sheet and liquidity
•At the end of the fourth quarter 2020, we had approximately $3.7 billion of
liquidity, comprised of an undrawn $3.0 billion Credit Facility and $0.7 billion
in cash. We remain investment grade at all three primary rating agencies.
•In 2020, we generated $1.5 billion of cash provided by operating activities
despite the lower commodity price realizations and decreased production volumes.
This was sufficient to fund our capital expenditures, share repurchases and
dividends.
•In early July 2020, collected an $89 million cash refund related to alternative
minimum tax credits and associated interest. This was an accelerated refund due
to the passage of the Coronavirus Aid, Relief, and Economic Security Act.
•In the fourth quarter of 2020, we realized over $400 million of cash from
operations. Our U.S. segment average realized prices for crude and NGLs for the
quarter were $39.71 and $16.30, respectively.
•We reduced our gross debt by $100 million and reduced our next significant debt
maturity.
•We remarketed $400 million sub-series B (tax-exempt) bonds in August at a
weighted average interest rate of 2.25%.
•In October, we completed a cash tender for $500 million of our then-outstanding
$1 billion 2.8% 2022 Notes, funded by cash on hand.
•The next significant debt maturity is the remaining $500 million 2.8% Senior
Notes due in November 2022.
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•During the second quarter 2020, we temporarily suspended the quarterly dividend
and share repurchases to maximize liquidity. On October 1, the Board of
Directors approved and declared the reinstatement of the base quarterly dividend
of $0.03 per share, effective in the fourth quarter of 2020. While our share
repurchase program remains approved with $1.3 billion of repurchase
authorization remaining at year-end, we decided to maintain the suspension as we
continue to maximize liquidity.
Managed our cost structure
•Achieved lower production expense rates in the U.S. segment due to lower
operational activity and cost management efforts
•Reduced our general and administrative expenses, primarily a result of
broad-based cost saving measures, including temporary base salary reductions for
CEO and other corporate officers through year-end, a reduction in Board of
Director compensation through year-end, and U.S. employee and contractor
workforce reductions.
Financial and operational results
•Total net sales volumes for the year were 383 mboed, including 306 mboed in the
U.S. Our U.S. net sales volumes decreased 5% and our wells to sales decreased
51% compared to 2019 as a result of lower drilling activity and natural field
decline. We drilled and completed fewer wells in direct response to lower market
prices.
•Our net loss per share was $1.83 in 2020 as compared to a net income per share
of $0.59 last year.
Items that contributed to the increase in our net loss in 2020, as compared to
2019, include:
•A decrease in revenues of approximately 39% compared to 2019, as a result of
decreased commodity price realizations and lower net sales volumes. The
combination of lower prices and lower volumes was the single largest contributor
to our net loss in 2020.
•A loss from our equity method investments totaling $161 million, primarily due
to $171 million of cumulative impairments in 2020 of an investment in an equity
method investee; our 2019 income from equity method investments totaled $87
million.
•An increase in exploration and impairment expenses of $152 million, primarily a
result of non-cash impairment charges related to goodwill and certain proved and
unproved properties in our REx portfolio. See Item 8. Financial Statements and
Supplementary Data -   Note 12   to the consolidated financial statements for
further detail.
•A lower income tax benefit of $74 million. The larger tax benefit in 2019 is
primarily related to the settlement of the 2010-2011 IRS Audit in the first
quarter of 2019. The tax benefit for 2020 was negligible due to no federal tax
benefit on the U.S. loss due to the valuation allowance on our net federal
deferred tax assets in the U.S. See Consolidated Results of Operations: 2020
compared to 2019 section below and Item 8. Financial Statements and
Supplementary Data -   Note 8   to the consolidated financial statements for
further detail.
Items that partially offset the above include:
•A gain on commodity derivatives of $116 million, compared to a net loss of $72
million in 2019.
•A decline in production expense of $157 million and general and administrative
expense of $82 million as discussed above.
Compensation and ESG Highlights and Initiatives
•CEO and Board of Director total compensation reduced by approximately 25% with
Board compensation mix shifted more toward equity and CEO mix further aligned
with broader industry norms, exclusive of temporary reductions announced in
2020.
•Achieved second consecutive year of record safety performance in 2020, as
measured by total recordable incident rate (TRIR) for both employees and
contractors.
•Short-term incentive scorecard for compensation updated to focus on safety,
environmental performance, capital efficiency, capital discipline/free cash flow
generation and financial/balance sheet strength.
•Added a 2021 GHG emissions intensity target to short-term incentive scorecard.
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Outlook


In February 2021, we announced a 2021 Capital Budget of $1.0 billion, which is
effectively a maintenance Capital Budget. We expect this maintenance-level
Capital Budget will allow us to keep total company oil production in 2021
consistent with our fourth quarter 2020 exit rate. Our 2021 Capital Budget is
consistent with our capital allocation framework that prioritizes corporate
returns and free cash flow generation over production growth.
The 2021 Capital Budget is weighted towards the four U.S. resource plays with
approximately 92% allocated to the Eagle Ford and Bakken. Our 2021 Capital
Budget is disaggregated by reportable segment in the table below:
(In millions)                              Capital Budget
United States                             $          979
International and other corporate items               21
Total Capital Budget                      $        1,000



Operations
  The following table presents a summary of our sales volumes for each of our
segments. Refer to the Results of Operations section for a price-volume analysis
for each of the segments.
                                       Increase                  Increase
Net Sales Volumes           2020      (Decrease)      2019      (Decrease)      2018
United States (mboed)       306             (5) %       323            8  %       298
International (mboed)(a)     77            (15) %        91          (25) %       122
Total (mboed)               383             (7) %       414           (1) %       420


(a)   We closed on the sale of our Libya subsidiary in the first quarter of
2018, our interest in the Atrush block in Kurdistan in the second quarter of
2019 and our U.K. business in the third quarter of 2019. See Item 8. Financial
Statements and Supplementary Data -   Note 5   to the consolidated financial
statements for further information on dispositions.
United States
Net sales volumes in the segment were lower during the year ended December 31,
2020. In the second quarter of 2020, we began the process of transitioning to a
significantly lower level of drilling and completion activity across our
domestic portfolio, with our remaining resources allocated primarily to the
Bakken and Eagle Ford. As a result of the decreased drilling and completion
activity, fewer wells were brought to sales resulting in a decline in production
in 2020. The following tables provide additional details regarding net sales
volumes, sales mix and operational drilling activity for our significant
operations within this segment:
                                          Increase                  Increase
Net Sales Volumes              2020      (Decrease)      2019      (Decrease)      2018
 Equivalent Barrels (mboed)
Eagle Ford                      99             (7) %     106             (2) %     108
Bakken                         105              2  %     103             23  %      84
Oklahoma                        66            (15) %      78              5  %      74
Northern Delaware               27             (4) %      28             40  %      20
Other United States              9             13  %       8            (33) %      12
Total United States            306             (5) %     323              8  %     298


Sales Mix - U.S. Resource Plays - 2020    Eagle Ford             Bakken             Oklahoma           Northern Delaware            Total
Crude oil and condensate                     61%                  75%                 26%                     55%                    58%
Natural gas liquids                          18%                  14%                 30%                     20%                    19%
Natural gas                                  21%                  11%                 44%                     25%                    23%


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Drilling Activity - U.S. Resource Plays 2020 2019 2018
Gross Operated
Eagle Ford:
Wells drilled to total depth 88 127 123
Wells brought to sales 87 146 149
Bakken:
Wells drilled to total depth 63 73 78
Wells brought to sales 64 105 80
Oklahoma:
Wells drilled to total depth 9 68 55
Wells brought to sales 13 69 57
Northern Delaware:
Wells drilled to total depth 15 51 69
Wells brought to sales 19 54 52

•Eagle Ford - In 2020, our net sales volumes were 99 mboed including oil sales
of 61 mbbld. We brought 87 gross company-operated wells to sales in 2020 across
Karnes, Atascosa and Gonzales counties. New well production provided strong
initial production rates that partially offset the lower wells to sales and
natural field decline.
•Bakken - In 2020, our net sales volumes were 105 mboed, including oil sales of
79 mbbld. We brought 64 gross company-operated wells to sales in 2020. Improved
gas capture efforts resulted in higher gas and NGL sales that offset the lower
wells to sales.
•Oklahoma - In 2020, our net sales volumes were 66 mboed including oil sales of
17 mbbld. We brought 13 gross company-operated wells to sales in 2020. During
the second quarter, we suspended all drilling and completions operations in
Oklahoma.
•Northern Delaware - In 2020, our net sales volumes were 27 mboed including oil
sales of 15 mbbld. We brought 19 gross company-operated wells to sales in 2020.
During the second quarter, we suspended drilling and completions operations in
Northern Delaware.
International
Net sales volumes in the segment were lower during the year ended December 31,
2020 primarily due to timing of E.G. liftings and natural field decline, coupled
with the disposition of our U.K. business. The following table provides details
regarding net sales volumes for our operations within this segment:
Increase Increase
Net Sales Volumes 2020 (Decrease) 2019 (Decrease) 2018
Equivalent Barrels (mboed)
Equatorial Guinea 77 (9) % 85 (12) % 97
United Kingdom(a) - (100) % 5 (62) % 13
Libya - - % - (100) % 8
Other International - (100) % 1 (75) % 4
Total International 77 (15) % 91 (25) % 122
Equity Method Investees
LNG (mtd) 4,289 (13) % 4,933 (15) % 5,805
Methanol (mtd) 1,017 (6) % 1,082 (13) % 1,241
Condensate and LPG (boed) 10,288 (7) % 11,104 (15) % 13,034

(a) Includes natural gas acquired for injection and subsequent resale. •Equatorial Guinea - Net sales volumes in 2020 were lower than 2019 primarily due to timing of liftings and natural field decline. •United Kingdom - During 2019, we closed on the sale of our U.K. business. See

Note 5 to the consolidated financial statements for further information.


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•Libya - During the first quarter of 2018, we closed on the sale of our
subsidiary in Libya. See   Note 5   to the consolidated financial statements for
further information.
•Equity Method Investees - Net sales volumes in 2020 are tied to the volumes in
Equatorial Guinea which were lower in the current year as noted above.
Market Conditions
Crude oil and condensate and NGL benchmarks decreased in 2020 as compared to the
same period in 2019. As a result, we experienced decreased price realizations
associated with those benchmarks. Commodity prices are the most significant
factor impacting our revenues, profitability, operating cash flows, the amount
of capital we invest in our business, payment of dividends and funding of share
repurchases. Commodity prices declined substantially in the first half of 2020
resulting from demand contraction related to the global pandemic and increased
supply following the OPEC decision to increase production. A revised OPEC deal
to reduce production was agreed in the early second quarter of 2020 and prices
partially recovered through the end of the year. However, worldwide demand
remains below pre-pandemic levels and we continue to expect commodity prices to
remain volatile, which will affect our price realizations during 2021. See
  Item 1A. Risk Factors   and   Item 7. Management's Discussion and Analysis of
Financial Condition - Critical Accounting Estimates   for further discussion of
how declines in these commodity prices could impact us.

United States


 The following table presents our average price realizations and the related
benchmarks for crude oil and condensate, NGLs and natural gas for 2020, 2019 and
2018.
                                                                    Increase                                  Increase
                                                 2020              (Decrease)              2019              (Decrease)              2018
Average Price Realizations(a)
Crude oil and condensate (per bbl)(b)         $ 35.93                      (36) %       $ 55.80                      (12) %       $ 63.11
Natural gas liquids (per bbl)                   11.28                      (21) %         14.22                      (42) %         24.54
Natural gas (per mcf)(c)                         1.77                      (19) %          2.18                      (18) %          2.65

Benchmarks


WTI crude oil average of daily prices (per
bbl)                                          $ 39.34                      (31) %       $ 57.04                      (12) %       $ 64.90
Magellan East Houston ("MEH") crude oil
average of daily prices (per bbl)(d)            39.95                      (36) %            61.96
LLS crude oil average of daily prices (per
bbl)(d)                                                                                                                             70.04
Mont Belvieu NGLs (per bbl)(e)                  14.69                      (18) %         17.81                      (33) %         26.75
Henry Hub natural gas settlement date average
(per mmbtu)                                      2.08                      (21) %          2.63                      (15) %          3.09


(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 $2.14 per bbl and $0.67 per
bbl for 2020 and 2019, and decreased average price realizations by $4.60 per bbl
for 2018.
(c)Inclusion of realized gains (losses) on natural gas derivative instruments
would have had a minimal impact on average price realizations for the periods
presented.
(d)Benchmark change due to industry shift to MEH in the first quarter of 2019.
(e)Bloomberg Finance LLP: Y-grade Mix NGL of 55% ethane, 25% propane, 5% butane,
8% isobutane and 7% natural gasoline.
Crude oil and condensate - Price realizations may differ from benchmarks due to
the quality and location of the product.
Natural gas liquids - The majority of our sales volumes are at reference to Mont
Belvieu prices.
Natural gas - A significant portion of volumes are sold at bid-week prices, or
first-of-month indices relative to our producing areas.
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International

The following table presents our average price realizations and the related benchmark for crude oil for 2020, 2019 and 2018.


                                                                  Increase                                  Increase
                                               2020              (Decrease)              2019              (Decrease)              2018
Average Price Realizations
Crude oil and condensate (per bbl)          $ 28.36                      (47) %       $ 53.09                      (17) %       $ 64.25
Natural gas liquids (per bbl)                  1.00                      (29) %          1.40                      (38) %          2.27
Natural gas (per mcf)                          0.24                      (27) %          0.33                      (39) %          0.54

Benchmark


Brent (Europe) crude oil (per bbl)(a)       $ 41.76                      (35) %       $ 64.36                       (9) %       $ 71.06

(a) Average of monthly prices obtained from the United States Energy Information Agency website.

United Kingdom
Crude oil and condensate - Generally sold in relation to the Brent crude
benchmark. We closed on the sale of our U.K. business on July 1, 2019.
Equatorial Guinea
Crude oil and condensate - Alba field liquids production is primarily condensate
and generally sold in relation to the Brent crude benchmark. Alba Plant LLC
processes the rich hydrocarbon gas which is supplied by the Alba field under a
fixed-price long-term contract. Alba Plant LLC extracts NGLs and secondary
condensate which is then sold by Alba Plant LLC at market prices, with our share
of the revenue reflected in income from equity method investments on the
consolidated statements of income. Alba Plant LLC delivers the processed dry
natural gas to the Alba field for distribution and sale to AMPCO and EG LNG.
Natural gas liquids - Wet gas is sold to Alba Plant LLC at a fixed-price term
contract resulting in realized prices not tracking market price. Alba Plant LLC
extracts and keeps NGLs, which are sold at market price, with our share of
income from Alba Plant LLC being reflected in the income from equity method
investments on the consolidated statements of income.
Natural gas - Dry natural gas, processed by Alba Plant LLC on behalf of the Alba
field, is sold by the Alba field to EG LNG and AMPCO at fixed-price, long-term
contracts resulting in realized prices not tracking market price. We derive
additional value from the equity investment in our downstream gas processing
units EG LNG and AMPCO. EG LNG sells LNG on a market-based long-term contract
and AMPCO markets methanol at market prices.
Consolidated Results of Operations: 2020 compared to 2019
Revenues from contracts with customers are presented by segment in the table
below:
                                                         Year Ended December 31,
(In millions)                                               2020                2019
Revenues from contracts with customers
United States                                      $      2,924               $ 4,602
International                                               173

461


Segment revenues from contracts with customers     $      3,097

$ 5,063

Below is a price/volume analysis for each segment. Refer to the preceding

Operations and Market Conditions sections for additional detail related to our net sales volumes and average price realizations.


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Increase (Decrease) Related to

Year Ended Net Sales Year Ended
(In millions) December 31, 2019 Price Realizations Volumes December 31, 2020
United States Price/Volume Analysis
Crude oil and condensate $ 3,887 $ (1,285) $ (280) $ 2,322
Natural gas liquids 307 (63) (1) 243
Natural gas 349 (62) (12) 275
Other sales 59 84
Total $ 4,602 $ 2,924
International Price/Volume Analysis
Crude oil and condensate $ 398 $ (122) $ (136) $ 140
Natural gas liquids 5 (1) - 4
Natural gas 44 (10) (5) 29
Other sales 14 -
Total $ 461 $ 173

Net gain (loss) on commodity derivatives in 2020 was a net gain of $116 million,
compared to a net loss of $72 million in 2019. We have multiple crude oil,
natural gas and NGL derivative contracts that settle against various indices. We
record commodity derivative gains/losses as the index pricing and forward curves
change each period. See Note 16 to the consolidated financial statements for
further information.
Income (loss) from equity method investments decreased $248 million in 2020 from
2019 primarily due to impairments of $171 million to an investment in an equity
method investee in 2020. In addition, lower price realizations and lower net
sales volumes from equity method investments in E.G. contributed to the
decrease, primarily due to AMPCO's 2020 triennial turnaround, timing of liftings
and natural field decline. See Item 8. Financial Statements and Supplementary
Data - Note 24 to the consolidated financial statements for further
information on the equity method investee impairment.
Net gain on disposal of assets decreased $41 million in 2020 from 2019,
primarily as a result of the sale of our working interest in the Droshky field
(Gulf of Mexico) and U.K. business in 2019. We had minimal disposal activity in
2020. See Item 8. Financial Statements and Supplementary Data - Note 5 to
the consolidated financial statements for information about these dispositions.
Other income decreased $37 million in 2020 from 2019 primarily due to income
recognized in 2019 arising from indemnification payments received from Marathon
Petroleum Corporation ("MPC"). Pursuant to the Tax Sharing Agreement we entered
into with MPC in connection with the 2011 spin-off transaction, MPC agreed to
indemnify us for certain liabilities. The indemnity relates to tax and interest
allocable to MPC as a result of the closure of the 2010-2011 U.S. Federal Tax
Audit in the first quarter of 2019.
Production expenses decreased $157 million during 2020 from 2019. Production
expense in our United States segment decreased $94 million primarily due to
lower operational activity and continued cost management, specifically staffing
and contract labor. Production expense in our International segment decreased
$67 million primarily as a result of the sale of our U.K. business and our
non-operated interest in the Atrush block in Kurdistan in 2019.
The production expense rate (expense per boe) declined during 2020 in the United
States and International segments due to the aforementioned reasons.
The following table provides production expense and production expense rates
(expense per boe) for each segment:
(In millions; rate in $ per boe) 2020 2019

Increase (Decrease) 2020 2019 Increase (Decrease) Production Expense and Rate

                                      Expense                                        Rate
United States                                    $  494    $  588                 (16) %       $ 4.42    $ 4.98                 (11) %
International                                    $   59    $  126                 (53) %       $ 2.12    $ 3.76                 (44) %


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Shipping, handling and other operating expenses decreased $9 million in 2020
from 2019 primarily as a result of lower net sales volumes in our United States
segment, partially offset by higher marketing costs due to higher volumes
purchased for resale in 2020.
 Exploration expenses include unproved property impairments, dry well costs,
geological and geophysical and other, which increased $32 million during 2020
versus 2019. We impaired $78 million of unproved property leases in Louisiana
Austin Chalk in our United States segment in 2020 due to a combination of
factors, including our geological assessment, seismic information, timing of
lease expiration dates and decisions not to develop acreage deemed non-core.
This was partially offset by impairments of REx unproved leases in 2019, albeit
lower than 2020, driven by our decision not to drill certain leases. See Item 8.
Financial Statements and Supplementary Data -   Note 12   to the consolidated
financial statements for details of these items.
The following table summarizes the components of exploration expenses:
                                                    Year Ended December 31,
(In millions)                               2020                2019       Increase (Decrease)
Exploration Expenses
Unproved property impairments    $        157                  $  98                      60  %
Dry well costs                              2                     16                     (88) %
Geological and geophysical                  6                     18                     (67) %
Other                                      16                     17                      (6) %
Total exploration expenses       $        181                  $ 149                      21  %


Depreciation, depletion and amortization decreased $81 million in 2020 from
2019, primarily due to lower net sales volumes in the United States and E.G.
along with the sale of our U.K. business in 2019. Our segments apply the
units-of-production method to the majority of their assets, including
capitalized asset retirement costs; therefore, volumes have an impact on DD&A
expense.
The DD&A rate (expense per boe) is impacted by field-level changes in reserves,
capitalized costs and sales volume mix between fields. The DD&A rate for
International decreased primarily as a result of dispositions in 2019. The
following table provides DD&A expense and DD&A expense rates for each segment:
                                                                    Increase                                       Increase
(In millions; rate in $ per boe)            2020       2019        (Decrease)              2020       2019        (Decrease)
DD&A Expense and Rate                                    Expense                                          Rate
United States                            $ 2,211    $ 2,250                 (2) %       $ 19.76    $ 19.07                  4  %
International                            $    82    $   121                (32) %       $  2.89    $  3.61                (20) %


 Impairments increased $120 million in 2020 from 2019, primarily as a result of
a $95 million goodwill charge related to our International reporting unit and a
$49 million long-lived asset impairment related to a damaged, unsalvageable well
and related equipment in the Louisiana Austin Chalk. See Item 8. Financial
Statements and Supplementary Data -   Note 12   for discussion of impairments in
further detail.
Taxes other than income include production, severance and ad valorem taxes,
primarily in the U.S., which tend to increase or decrease in relation to revenue
and sales volumes. Taxes other than income decreased $111 million in 2020 from
2019 period primarily due to lower price realizations and lower sales volumes in
the U.S. segment.
General and administrative expenses decreased $82 million in 2020 compared to
2019, which reflects costs savings realized from workforce reductions.
Provision (benefit) for income taxes reflects an effective income tax rate of 1%
for 2020, as compared to an effective income tax rate of (22)% for 2019. See
Item 8. Financial Statements and Supplementary Data -   Note 8   to the
consolidated financial statements for a discussion of the effective income tax
rate.
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Segment Results: 2020 compared to 2019


  Segment Income
Segment income represents income which excludes certain items not allocated to
our operating segments, net of income taxes. A portion of our corporate and
operations general and administrative support costs are not allocated to the
operating segments. These unallocated costs primarily consist of employment
costs (including pension effects), professional services, facilities and other
costs associated with corporate and operations support activities. Additionally,
items which affect comparability such as: gains or 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 gains or losses on
commodity and interest rate derivative instruments, effects of pension
settlements and curtailments, or other items (as determined by the CODM) are not
allocated to operating segments.
The following table reconciles segment income (loss) to net income (loss):
                                                                        Year Ended December 31,
(In millions)                                             2020                  2019            Increase (Decrease)
United States                                       $         (553)         $     675                        (182) %
International                                                   30                233                         (87) %
Segment income (loss)                                         (523)               908                        (158) %
Items not allocated to segments, net of income
taxes(a)                                                      (928)              (428)                       (117) %
Net income (loss)                                   $       (1,451)         $     480                        (402) %


(a)  See Item 8. Financial Statements and Supplementary Data -   Note 7   to the
consolidated financial statements for further detail about items not allocated
to segments.
United States segment income (loss) in 2020 was an after-tax loss of $553
million versus after-tax income of $675 million in 2019, primarily as a result
of lower crude price realizations and lower net sales volumes, which was
partially offset by higher gain realized on commodity derivatives, and lower
production taxes and production expenses.
 International segment income in 2020 was after-tax income of $30 million versus
after-tax income of $233 million in 2019, primarily due to lower price
realizations and sales volumes, partially offset by lower costs due to the sale
of our U.K. business and our non-operated interest in the Atrush block in
Kurdistan in 2019.
Consolidated Results of Operations: 2019 compared to 2018
  A detailed discussion of the year-over-year changes from the year ended
December 31, 2019 to December 31, 2018 can be found in the Management's
Discussion and Analysis section of our Annual Report on Form 10-K for the year
ended December 31, 2019 and is available via the SEC's website at www.sec.gov
and on our website at www.marathonoil.com.
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Management's Discussion and Analysis of Financial Condition, Cash Flows and
Liquidity
Commodity prices are the most significant factor impacting our operating cash
flows and the amount of capital available to reinvest into the business. In
2020, we experienced a decrease in operating cash flows primarily as a result of
lower commodity price realizations, with crude oil and condensate price
realizations decreasing by 36% to $35.39 per barrel. In direct response to the
lower commodity prices, we reduced our 2020 Capital Budget such that the Capital
Budget did not exceed cash provided by operations.
At December 31, 2020, we had approximately $3.7 billion of liquidity consisting
of $742 million in cash and cash equivalents and $3.0 billion available under
our Credit Facility. As previously discussed in the Outlook section, our Capital
Budget for 2021 is $1.0 billion. Our top priorities for using cash provided by
operations are to fund our Capital Budget and base dividend while also enhancing
liquidity. We believe our current liquidity level, cash flow from operations and
ability to access the capital markets provides us with the flexibility to fund
our initiatives across a wide range of commodity price environments.
Cash Flows
The following table presents sources and uses of cash and cash equivalents for
2020 and 2019:
                                                                      Year Ended December 31,
(In millions)                                                        2020                  2019
Sources of cash and cash equivalents
Operating activities                                           $       1,473          $     2,749
Disposal of assets, net of cash transferred to the buyer                  18                  (76)
Borrowings                                                               400                  600
Other                                                                      8                   65
Total sources of cash and cash equivalents                     $       1,899          $     3,338
Uses of cash and cash equivalents
Additions to property, plant and equipment                     $      (1,343)         $    (2,550)
Additions to other assets                                                 15                   36
Acquisitions, net of cash acquired                                        (1)                (293)
Purchases of common stock                                                (92)                (362)
Debt repayments                                                         (500)                (600)
Dividends paid                                                           (64)                (162)
Other                                                                    (30)                 (11)
Total uses of cash and cash equivalents                        $

(2,015) $ (3,942)

The following table shows capital expenditures by segment and reconciles to
additions to property, plant and equipment as presented in the consolidated
statements of cash flows:
Year Ended December 31,
(In millions) 2020 2019
United States $ 1,137 $ 2,550
International 1 16
Corporate 13 25
Total capital expenditures 1,151 2,591
Change in capital expenditure accrual 192 (41)
Total use of cash and cash equivalents for property, plant and
equipment $ 1,343 $ 2,550

During the third and fourth quarters of 2020, we completed two separate
financing transactions resulting in a remarketing of $400 million of sub-series
B bonds to investors and a separate debt repayment of $500 million, which is
further discussed in the Capital Resources section below. Also see Item 8.
Financial Statements and Supplementary Data - Note 18 to the consolidated
financial statements for details of these transactions.
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During the first quarter of 2020, the Board of Directors approved a $0.05 per
share dividend. The Board of Directors temporarily suspended our quarterly
dividend payment in the second quarter as we prioritized liquidity and our
balance sheet given the macro environment. During the fourth quarter of 2020,
the Board of Directors approved the reinstatement of the dividend and declared a
base quarterly dividend of $0.03 per share. During 2019, the Board of Directors
approved a $0.05 per share dividend each quarter.
Available Liquidity
Our main sources of liquidity are cash and cash equivalents, internally
generated cash flow from operations, sales of non-core assets, capital market
transactions and our revolving Credit Facility. At December 31, 2020, we had
approximately $3.7 billion of liquidity consisting of $742 million in cash and
cash equivalents and $3.0 billion available under our revolving Credit Facility.
See Item 8. Financial Statements and Supplementary Data - Note 26 to the
consolidated financial statements for a further discussion of how our
commitments and contingencies could affect our available liquidity.
Our working capital requirements are supported by our cash and cash equivalents
and our Credit Facility. We may draw on our revolving Credit Facility to meet
short-term cash requirements, or issue debt or equity securities through the
shelf registration statement discussed below as part of our longer-term
liquidity and capital management program. Because of the alternatives available
to us as discussed above, we believe that our short-term and long-term liquidity
are adequate to fund not only our current operations, but also our near-term and
long-term funding requirements including our capital spending programs, dividend
payments, defined benefit plan contributions, repayment of debt maturities and
other amounts that may ultimately be paid in connection with contingencies.
General economic conditions, commodity prices and financial, business and other
factors, including the global pandemic, could affect our operations and our
ability to access the capital markets.
During the first half of 2020, commodity prices significantly declined due to
the combined impacts of global crude oil oversupply and lower demand for
hydrocarbons due to the global pandemic. As a result, credit rating agencies
reviewed many companies in the industry, including us. We continue to be rated
investment grade at all three primary credit rating agencies. A downgrade in our
credit ratings could increase our future cost of financing or limit our ability
to access capital, and could result in additional credit support requirements.
See Item 1A. Risk Factors for a discussion of how a downgrade in our credit
ratings could affect us.
We may incur additional debt in order to fund our capital expenditures,
acquisitions or development activities or for general corporate or other
purposes. A higher level of indebtedness could increase the risk that our
liquidity and financial flexibility deteriorates. See Item 1A. Risk Factors
for a further discussion of how our level of indebtedness could affect us.
Capital Resources
Credit Arrangements and Borrowings
As of December 31, 2020, we had no borrowings on our $3.0 billion Credit
Facility. At December 31, 2020, we had $5.4 billion of total debt outstanding.
In October 2020, we completed a cash tender offer for an aggregate principal
amount of $500 million of our then-outstanding $1 billion 2.8% senior notes due
2022. Our next significant debt maturity is the remaining $500 million 2.8%
senior notes that are due in November 2022. We do not have any triggers on any
of our corporate debt that would cause an event of default in the case of a
downgrade of our credit ratings.
On August 18, 2020, we closed a $400 million remarketing to investors of
sub-series B bonds which are part of the $1.0 billion St. John the Baptist,
State of Louisiana revenue refunding bonds originally issued and purchased in
December 2017. Information about these bonds are available on the website of the
Municipal Securities Rulemaking Board via its Electronic Municipal Market Access
system at www.msrb.org. Information on that website is not incorporated by
reference into this filing.
In 2018, we signed an agreement with an owner/lessor to construct and lease a
new build-to-suit office building in Houston, Texas. The lessor and other
participants are providing financing for up to $340 million to fund the
estimated project costs, which was reduced effective August 2020 from $380
million to align with our revised estimate of the project costs. As of
December 31, 2020, project costs incurred totaled approximately $144 million,
including land acquisition and construction costs.
Shelf Registration
We have a universal shelf registration statement filed with the SEC under which
we, as a "well-known seasoned issuer" for purposes of SEC rules, have the
ability to issue and sell an indeterminate amount of various types of debt and
equity securities.
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Debt-To-Capital Ratio
The Credit Facility includes a single financial covenant requiring that our
ratio of total debt to total capitalization not exceed 65% as of the last day of
each fiscal quarter. This covenant calculation was modified in December 2020,
when we executed the fifth amendment to our credit facility. The primary changes
resulting from this amendment are (i) a modification to the debt to total
capitalization covenant calculation that permits an add-back to shareholders'
equity for certain non-cash write-downs, (ii) the addition of certain customary
events of default, including a cross payment event of default and (iii) certain
restrictions on the incurrence of subsidiary indebtedness. Under the amended
definition, our total debt to total capitalization ratio was 26% at December 31,
2020.
Capital Requirements
Capital Spending
Our approved Capital Budget for 2021 is $1.0 billion. Additional details were
previously discussed in Outlook .
Share Repurchase Program
In 2020, we acquired approximately 9 million common shares at a cost of $85
million under our share repurchase program. While the share repurchase program
remains approved and has $1.3 billion of remaining authorization, we elected to
suspend additional share repurchases to preserve liquidity.
On January 27, 2021, our Board of Directors approved a dividend of $0.03 per
share for the fourth quarter of 2020. The dividend is payable on March 10, 2021
to shareholders of record on February 17, 2021.
We plan to make contributions of up to $40 million to our funded pension plans
during 2021. Cash contributions to be paid from our general assets for the
unfunded pension and postretirement plans are expected to be approximately $3
million and $10 million in 2021.
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Contractual Cash Obligations
The table below provides aggregated information on our consolidated obligations
to make future payments under existing contracts as of December 31, 2020.
2022- 2024- Later
(In millions) Total 2021 2023 2025 Years
Short and long-term debt (includes
interest)(a) $ 7,985 $ 247 $ 1,407 $ 1,691 $ 4,640
Lease obligations 287 77 55 9 146 (g)
Purchase obligations:
Oil and gas activities(b) 26 16 2 1 7
Service and materials contracts(c) 53 31 21 1 -
Transportation and related contracts 1,555 208 445 405 497

Other (d) 19 19 - - -
Total purchase obligations 1,653 274 468 407 504
Other long-term liabilities reported in
the consolidated balance sheet(e) 316 31 55 48 182

Total contractual cash obligations(f) $ 10,241 $ 629 $ 1,985 $ 2,155 $ 5,472

(a)Includes anticipated cash payments for interest of $247 million for 2021,
$471 million for 2022-2023, $391 million for 2024-2025 and $1.4 billion for the
remaining years for a total of $2.5 billion.
(b)Includes contracts to acquire property, plant and equipment and commitments
for oil and gas drilling and completion activities.
(c)Includes contracts to purchase services such as utilities, supplies and
various other maintenance and operating services.
(d)Includes any drilling rigs and fracturing crews that are not considered lease
obligations.
(e)Primarily includes obligations for pension and other postretirement benefits
including medical and life insurance. We have estimated projected funding
requirements through 2027. Although unrecognized tax benefits are not a
contractual obligation, they are presented in this table because they represent
potential demands on our liquidity.
(f)This table does not include the estimated discounted liability for
dismantlement, abandonment and restoration costs of oil and gas properties of
$254 million. See Item 8. Financial Statements and Supplementary Data - Note
13 to the consolidated financial statements.
(g)Includes $144 million of project costs incurred as of December 31, 2020 for a
new build-to-suit office building in Houston, Texas. See Item 8. Financial
Statements and Supplementary Data - Note 14 to the consolidated financial
statements and Off-Balance Sheet Arrangements section below.

Transactions with Related Parties
Offshore E.G, we own a 63% working interest in the Alba field. Onshore E.G., we
own a 52% interest in an LPG processing plant, a 60% interest in an LNG
production facility and a 45% interest in a methanol production plant, each
through equity method investees. We sell our natural gas from the Alba field to
these equity method investees as the feedstock for their production processes.
Off-Balance Sheet Arrangements
Off-balance sheet arrangements comprise those arrangements that may potentially
impact our liquidity, capital resources and results of operations, even though
such arrangements are not recorded as liabilities under accounting principles
generally accepted in the U.S. Although off-balance sheet arrangements serve a
variety of our business purposes, we are not dependent on these arrangements to
maintain our liquidity and capital resources, and we are not aware of any
circumstances that are reasonably likely to cause the off-balance sheet
arrangements to have a material adverse effect on liquidity and capital
resources.
We will issue stand-alone letters of credit when required by a business partner.
Such letters of credit outstanding at December 31, 2020, 2019 and 2018
aggregated $14 million, $14 million and $52 million. Most of the letters of
credit are in support of obligations recorded in the consolidated balance sheet.
In 2019, our letters of credit outstanding decreased as a result of our upgraded
credit rating and the sale of our U.K. business (we no longer have requirements
to support firm transportation agreements and future abandonment liabilities).
In 2018, we signed an agreement with an owner/lessor to construct and lease a
new build-to-suit office building in Houston, Texas. The lessor and other
participants are providing financing for up to $340 million, to fund the
estimated project costs, which was reduced effective August 2020, from
$380 million to align with our revised estimate of the project costs. As of
December 31, 2020 project costs incurred totaled $144 million, primarily for
land acquisition and initial design costs. The initial lease term is five years
and will commence once construction is substantially complete and the new
Houston office is ready for occupancy. At the end of the initial lease term, we
can extend the term of the lease for an additional five years, subject
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to the approval of the participants; purchase the property subject to certain
terms and conditions; or remarket the property to an unrelated third party. The
lease contains a residual value guarantee of approximately 89% of the total
acquisition and construction costs. See Item 8. Financial Statements and
Supplementary Data - Note 14 to the consolidated financial statements for
further information on leases.
Management's Discussion and Analysis of Environmental Matters, Litigation and
Contingencies
We have incurred and will continue to incur capital, operating and maintenance
and remediation expenditures as a result of environmental laws and regulations.
If these expenditures, as with all costs, are not ultimately offset by the
prices of our products and services, our operating results will be adversely
affected. We believe that substantially all of our competitors must comply with
similar environmental laws and regulations. However, the specific impact on each
competitor may vary depending on a number of factors, including the age and
location of its operating facilities, marketing areas and production processes.
These laws generally provide for control of pollutants released into the
environment and require responsible parties to undertake remediation of
hazardous waste disposal sites. Penalties may be imposed for noncompliance.
We accrue for environmental remediation activities when the responsibility to
remediate is probable and the amount of associated costs can be reasonably
estimated. As environmental remediation matters proceed toward ultimate
resolution or as additional remediation obligations arise, charges in excess of
those previously accrued may be required.
New or expanded environmental requirements, which could increase our
environmental costs, may arise in the future on both state and federal levels.
We strive to comply with all legal requirements regarding the environment, but
as not all costs are fixed or presently determinable (even under existing
legislation) and may be affected by future legislation or regulations, it is not
possible to predict all of the ultimate costs of compliance, including
remediation costs that may be incurred and penalties that may be imposed.
For more information on environmental regulations that impact us, or could
impact us, see Item 1. Business - Environmental, Health and Safety Matters ,
Item 1A. Risk Factors and Item 3. Legal Proceedings .
Critical Accounting Estimates
The preparation of financial statements in accordance with accounting principles
generally accepted in the U.S. requires us to make estimates and assumptions
that affect the reported amounts of assets and liabilities and the disclosure of
contingent assets and liabilities as of the date of the consolidated financial
statements and the reported amounts of revenues and expenses during the
respective reporting periods. Accounting estimates are considered to be critical
if (1) the nature of the estimates and assumptions is material due to the levels
of subjectivity and judgment necessary to account for highly uncertain matters
or the susceptibility of such matters to change, and (2) the impact of the
estimates and assumptions on financial condition or operating performance is
material. Actual results could differ from the estimates and assumptions used.
Estimated Quantities of Net Reserves
We use the successful efforts method of accounting for our oil and gas producing
activities. The successful efforts method inherently relies on the estimation of
proved crude oil and condensate, NGLs and natural gas reserves. The amount of
estimated proved reserve volumes affect, among other things, whether certain
costs are capitalized or expensed, the amount and timing of costs depreciated,
depleted or amortized into net income and the presentation of supplemental
information on oil and gas producing activities. In addition, the expected
future cash flows to be generated by producing properties are used for testing
impairment and the expected future taxable income available to realize deferred
tax assets, also in part, rely on estimates of quantities of net reserves. Refer
to the applicable sections below for further discussion of these accounting
estimates.
The estimation of quantities of net reserves is a highly technical process
performed by our petroleum engineers and geoscientists for crude oil and
condensate, NGLs and natural gas, which is based upon several underlying
assumptions. The reserve estimates may change as additional information becomes
available and as contractual, operational, economic and political conditions
change. We evaluate our reserves using drilling results, reservoir performance,
subsurface interpretation and future plans to develop acreage. Technologies used
in proved reserves estimation includes statistical analysis of production
performance, decline curve analysis, pressure and rate transient analysis,
pressure gradient analysis, reservoir simulation and volumetric analysis. The
observed statistical nature of production performance coupled with highly
certain reservoir continuity or quality within the reliable technology areas and
sufficient proved developed locations establish the reasonable certainty
criteria required for booking proved reserves. As per SEC requirements, proved
undeveloped reserve volumes are limited to activity in the 5-year plan and wells
that will be developed within 5 years of initial booking. The data for a given
reservoir may also change over time as a result of numerous factors including,
but not limited to, additional development activity and future development
costs, production history and continual reassessment of the viability of future
production volumes under varying economic conditions.
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Reserve estimates are based on an unweighted arithmetic average of commodity
prices during the 12-month period, using the closing prices on the first day of
each month, as defined by the SEC. The table below provides the 2020 SEC pricing
for certain benchmark prices:
2020 SEC Pricing
WTI crude oil (per bbl) $ 39.57
Henry Hub natural gas (per mmbtu) $ 1.99
Brent crude oil (per bbl) $ 41.77
Mont Belvieu NGLs (per bbl) $ 14.41

When determining the December 31, 2020 proved reserves for each property, the
benchmark prices listed above were adjusted using price differentials that
account for property-specific quality and location differences.
If the future average crude oil prices are below the average prices used to
determine proved reserves at December 31, 2020, it could have an adverse effect
on our estimates of proved reserve volumes and the value of our business. Future
reserve revisions could also result from changes in capital funding, drilling
plans and governmental regulation, among other things. It is difficult to
estimate the magnitude of any potential price change and the effect on proved
reserves, due to numerous factors (including future crude oil price and
performance revisions). For further discussion of risks associated with our
estimation of proved reserves, see Part I. Item 1A. Risk Factors .
Depreciation and depletion of crude oil and condensate, NGLs and natural gas
producing properties is determined by the units-of-production method and could
change with revisions to estimated proved reserves. While revisions of previous
reserve estimates have not historically been significant to the depreciation and
depletion rates of our segments, any reduction in proved reserves, could result
in an acceleration of future DD&A expense. The following table illustrates, on
average, the sensitivity of each segment's units-of-production DD&A per boe and
pretax income to a hypothetical 10% change in 2020 proved reserves based on 2020
production.
Impact of a 10% Increase in Proved Impact of a 10% Decrease in Proved
Reserves Reserves
(In millions, except per boe) DD&A per boe Pretax Income DD&A per boe Pretax Income
United States $ (1.80) $ 201 $ 2.20 $ (246)
International $ (0.26) $ 7 $ 0.32 $ (9)

Fair Value Estimates
Fair value is the price that would be received to sell an asset or paid to
transfer a liability in an orderly transaction between market participants at
the measurement date. There are three approaches for measuring the fair value of
assets and liabilities: the market approach, the income approach and the cost
approach, each of which includes multiple valuation techniques. The market
approach uses prices and other relevant information generated by market
transactions involving identical or comparable assets or liabilities. The income
approach uses valuation techniques to measure fair value by converting future
amounts, such as cash flows or earnings, into a single present value, or range
of present values, using current market expectations about those future amounts.
The cost approach is based on the amount that would currently be required to
replace the service capacity of an asset. This is often referred to as current
replacement cost. The cost approach assumes that the fair value would not exceed
what it would cost a market participant to acquire or construct a substitute
asset of comparable utility, adjusted for obsolescence.
The fair value accounting standards do not prescribe which valuation technique
should be used when measuring fair value and do not prioritize among the
techniques. These standards establish a fair value hierarchy that prioritizes
the inputs used in applying the various valuation techniques. Inputs broadly
refer to the assumptions that market participants use to make pricing decisions,
including assumptions about risk. Level 1 inputs are given the highest priority
in the fair value hierarchy while Level 3 inputs are given the lowest priority.
The three levels of the fair value hierarchy are as follows:
•Level 1 - Observable inputs that reflect unadjusted quoted prices for identical
assets or liabilities in active markets as of the measurement date. Active
markets are those in which transactions for the asset or liability occur in
sufficient frequency and volume to provide pricing information on an ongoing
basis.
•Level 2 - Observable market-based inputs or unobservable inputs that are
corroborated by market data. These are inputs other than quoted prices in active
markets included in Level 1, which are either directly or indirectly observable
as of the measurement date.
•Level 3 - Unobservable inputs that are not corroborated by market data and may
be used with internally developed methodologies that result in management's best
estimate of fair value.
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Valuation techniques that maximize the use of observable inputs are favored.
Assets and liabilities are classified in their entirety based on the lowest
priority level of input that is significant to the fair value measurement. The
assessment of the significance of a particular input to the fair value
measurement requires judgment and may affect the placement of assets and
liabilities within the levels of the fair value hierarchy. See Item 8. Financial
Statements and Supplementary Data - Note 17 to the consolidated financial
statements for disclosures regarding our fair value measurements.
Significant uses of fair value measurements include:
•assets and liabilities acquired in a business combination;
•assets acquired in an asset acquisition;
•impairment assessments of long-lived assets;
•impairment assessments of equity method investments;
•impairment assessments of goodwill;
•recorded value of derivative instruments; and
•recorded value of pension plan assets.
The need to test long-lived assets and goodwill for impairment can be based on
several indicators, including a significant reduction in prices of crude oil and
condensate, NGLs and natural gas, sustained declines in our common stock,
reductions to our Capital Budget, unfavorable adjustments to reserves,
significant changes in the expected timing of production, other changes to
contracts or changes in the regulatory environment in which the property is
located.
Impairment Assessments of Long-Lived Assets
Long-lived assets in use are assessed for impairment whenever changes in facts
and circumstances indicate that the carrying value of the assets may not be
recoverable. For purposes of an impairment evaluation, long-lived assets must be
grouped at the lowest level for which independent cash flows can be identified,
which generally is field-by-field or, in certain instances, by logical grouping
of assets if there is significant shared infrastructure or contractual terms
that cause economic interdependency amongst separate, discrete fields. If the
sum of the undiscounted estimated cash flows from the use of the asset group and
its eventual disposition is less than the carrying value of an asset group, the
carrying value is written down to the estimated fair value.
Fair value calculated for the purpose of testing our long-lived assets for
impairment is estimated using the present value of expected future cash flows
method and comparative market prices when appropriate. Significant judgment is
involved in performing these fair value estimates since the results are based on
forecasted assumptions. Significant assumptions include:
•Future crude oil and condensate, NGLs and natural gas prices. Our estimates of
future prices are based on our analysis of market supply and demand and
consideration of market price indicators. Although these commodity prices may
experience extreme volatility in any given year, we believe long-term industry
prices are driven by global market supply and demand. To estimate supply, we
consider numerous factors, including the worldwide resource base, depletion
rates and OPEC production policies. We believe demand is largely driven by
global economic factors, such as population and income growth, governmental
policies and vehicle stocks. The prices we use in our fair value estimates are
consistent with those used in our planning and capital investment reviews. There
has been significant volatility in crude oil and condensate, NGLs and natural
gas prices and estimates of such future prices are inherently imprecise. See
Item 1A. Risk Factors for further discussion on commodity prices.
•Estimated quantities of crude oil and condensate, NGLs and natural gas. Such
quantities are based on a combination of proved reserves and risk-weighted
probable reserves and resources such that the combined volumes represent the
most likely expectation of recovery. See Item 1A. Risk Factors for further
discussion on reserves.
•Expected timing of production. Production forecasts are the outcome of
engineering studies which estimate reserves, as well as expected capital
programs. The actual timing of the production could be different than the
projection. Cash flows realized later in the projection period are less valuable
than those realized earlier due to the time value of money. The expected timing
of production that we use in our fair value estimates is consistent with that
used in our planning and capital investment reviews.
•Discount rate commensurate with the risks involved. We apply a discount rate to
our expected cash flows based on a variety of factors, including market and
economic conditions, operational risk, regulatory risk and political risk. A
higher discount rate decreases the net present value of cash flows.
•Future capital requirements. Our estimates of future capital requirements are
based upon a combination of authorized spending and internal forecasts.
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We base our fair value estimates on projected financial information which we
believe to be reasonably likely to occur. An estimate of the sensitivity to
changes in assumptions in our undiscounted cash flow calculations is not
practicable, given the numerous assumptions (e.g. reserves, pace and timing of
development plans, commodity prices, capital expenditures, operating costs,
drilling and development costs, inflation and discount rates) that can
materially affect our estimates. Unfavorable adjustments to some of the above
listed assumptions would likely be offset by favorable adjustments in other
assumptions. For example, the impact of sustained reduced commodity prices on
future undiscounted cash flows would likely be partially offset by lower costs.
As of December 31, 2020 our estimated undiscounted cash flows relating to our
remaining long-lived assets significantly exceeded their carrying values.
During 2020, we recorded impairment charges totaling $133 million related to
proved and certain unproved properties. See Item 8. Financial Statements and
Supplementary Data Note 12 and Note 17 to the consolidated financial
statements for discussion of impairments recorded in 2020, 2019 and 2018 and the
related fair value measurements.
Impairment Assessment of Equity Method Investments
During 2020, we recorded impairment charges totaling $171 million pertaining to
an investment in an equity method investee, which was reflected in income (loss)
from equity method investments in our consolidated statements of income. Equity
method investments are assessed for impairment whenever changes in the facts and
circumstances indicate a loss in value may have occurred. When a loss is deemed
to have occurred that is other than temporary, the carrying value of the equity
method investment is written down to fair value.
Fair value calculated for the purpose of testing our equity method investees for
impairment is estimated using the present value of expected future cash flows
method. Significant judgment is involved in performing these fair value
estimates since the results are based on forecasted assumptions and the
performance of entities that we do not control. Significant assumptions include:
•Future condensate, NGL, LNG, natural gas and methanol prices. Our estimates of
future prices are based on our analysis of market supply and demand and
consideration of market price indicators. Although these commodity prices may
experience extreme volatility in any given year, we believe long-term industry
prices are driven by global market supply and demand. To estimate supply, we
consider numerous factors, including the worldwide resource base, depletion
rates and OPEC production policies. We believe demand is largely driven by
global economic factors, such as population and income growth, and governmental
policies. The prices we use in our fair value estimates are consistent with
those used in our planning and capital investment reviews. There has been
significant volatility in commodity prices and estimates of such future prices
are inherently imprecise.
•Estimated quantities of feedstock condensate, NGLs and natural gas processed by
our investees. There are two primary sets of inputs used to estimate feedstock
volumes processed by our investees. The first input involves hydrocarbons
produced from our Alba Field. Our equity method investees currently process
hydrocarbons from our Alba Field, which consists of condensate, NGLs and natural
gas reserves. Estimated quantities of hydrocarbons processed from our Alba Field
are based on a combination of proved reserves and risk-weighted probable
reserves and resources such that the combined volumes represent the most likely
expectation of recovery.

The second input involves our estimate of future third-party gas to be processed
by our investees. Our investees have capacity to process hydrocarbons from
sources other than our Alba field. During 2019, we executed agreements for
processing natural gas produced from the third party-owned Alen Unit through the
existing Alba Plant LLC LPG processing plant and the EGHoldings LNG production
facility beginning in 2021. Estimated natural gas volumes processed from the
Alen Unit were based on forecasts received from the operator of the Alen Unit.

•Expected timing of production. Production forecasts are the outcome of
engineering studies which estimate reserves, as well as expected capital
programs. The actual timing of the production could be different than the
projection. Cash flows realized later in the projection period are less valuable
than those realized earlier due to the time value of money. The expected timing
of production from the Alba Field that we use in our fair value estimates is
consistent with that used in our planning and capital investment reviews. The
expected timing of production from the Alen Unit is consistent with forecasts
received from the operator of that field.
•Discount rate commensurate with the risks involved. We apply a discount rate to
our expected cash flows based on a variety of factors, including market and
economic conditions, operational risk, regulatory risk and political risk. A
higher discount rate decreases the net present value of cash flows.
We base our fair value estimates on projected financial information which we
believe to be reasonably likely to occur. This includes the estimated dividends
and/or return of capital we expect to be paid by our equity method investees,
which are directly affected by the significant assumptions described in the
preceding paragraphs. An estimate of the sensitivity to changes
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in assumptions in our cash flow calculations is not practicable, given the
numerous other assumptions (e.g. reserves, commodity prices, operating costs,
inflation and discount rates) that can materially affect our estimates.
Unfavorable adjustments to some of the above listed assumptions would likely be
offset by favorable adjustments in other assumptions.
See Note 12 to the consolidated financial statements for further information
regarding the impairment recognized during 2020.
Impairment Assessments of Goodwill
Goodwill is tested for impairment on an annual basis, or between annual tests
when events or changes in circumstances indicate the fair value may have been
reduced below its carrying value. Goodwill is tested for impairment at the
reporting unit level. Our reporting units are the same as our reporting
segments, of which historically only International included goodwill.
Determining the fair value of a reporting unit requires judgment and the use of
significant estimates and assumptions. Our policy is to first assess the
qualitative factors in order to determine whether the fair value of our
International reporting unit is more likely than not less than its carrying
amount. Certain qualitative factors used in our evaluation include, among other
things, the results of the most recent quantitative assessment of the goodwill
impairment test; macroeconomic conditions; industry and market conditions
(including commodity prices and cost factors); overall financial performance;
and other relevant entity-specific events. If, after considering these events
and circumstances we determined that it is more likely than not that the fair
value of the International reporting unit is less than its carrying amount, a
quantitative goodwill test is performed. The quantitative goodwill test is
performed using a combination of market and income approaches. The market
approach references observable inputs specific to us and our industry, such as
the price of our common equity, our enterprise value and valuation multiples of
us and our peers from the investor analyst community. The income approach
utilizes discounted cash flows, which are based on forecasted assumptions. Key
assumptions to the income approach are the same as those described above
regarding our impairment assessment of long-lived assets and are consistent with
those that management uses to make business decisions.
In the first quarter of 2020, a triggering event (significant decline in market
capitalization caused by worldwide declines in hydrocarbon demand and
corresponding prices) required us to assess our goodwill in the International
reporting unit for impairment as of March 31, 2020. We estimated the fair value
of our International reporting unit using a combination of market and income
approaches and concluded that a full impairment of $95 million was required. See
Item 8. Financial Statements and Supplementary Data Note 15 to the
consolidated financial statements for additional discussion of goodwill.
Derivatives
We record all derivative instruments at fair value. Fair value measurements for
all our derivative instruments are based on observable market-based inputs that
are corroborated by market data and are discussed in Item 8. Financial
Statements and Supplementary Data - Note 16 to the consolidated financial
statements. Additional information about derivatives and their valuation may be
found in Item 7A. Quantitative and Qualitative Disclosures About Market
Risk .
Pension Plan Assets
Pension plan assets are measured at fair value. See Item 8. Financial Statements
and Supplementary Data - Note 20 to the consolidated financial statements
for discussion of the fair value of plan assets and the presentation of the fair
value of our defined benefit pension plan's assets by level within the fair
value hierarchy as of December 31, 2020 and 2019.
Income Taxes
We are subject to income taxes in numerous taxing jurisdictions worldwide.
Estimates of income taxes to be recorded involve interpretation of complex tax
laws and assessment of the effects of foreign taxes on our U.S. federal income
taxes.
Uncertainty exists regarding tax positions taken in previously filed tax returns
which remain subject to examination, along with positions expected to be taken
in future returns. We provide for unrecognized tax benefits, based on the
technical merits, when it is more likely than not that an uncertain tax position
will not be sustained upon examination. Adjustments are made to the uncertain
tax positions when facts and circumstances change, such as the closing of a tax
audit; court proceedings; changes in applicable tax laws, including tax case
rulings and legislative guidance; or expiration of the applicable statute of
limitations.
We have recorded deferred tax assets and liabilities, measured at enacted tax
rates, for temporary differences between book basis and tax basis, tax credit
carryforwards and operating loss carryforwards. In accordance with U.S. GAAP
accounting standards, we routinely assess the realizability of our deferred tax
assets and reduce such assets, to the expected realizable amount, by a valuation
allowance if it is more likely than not that some portion or all of the deferred
tax assets will not be realized. In assessing the need for additional or
adjustments to existing valuation allowances, we consider all available positive
and negative evidence. Positive evidence includes reversals of temporary
differences, forecasts of future taxable income, assessment of future business
assumptions and applicable tax planning strategies that are prudent and
feasible. Negative
49
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evidence includes losses in recent years as well as the forecasts of future loss
in the realizable period. In making our assessment regarding valuation
allowances, we weight the evidence based on objectivity.
We base our future taxable income estimates on projected financial information
which we believe to be reasonably likely to occur. Numerous judgments and
assumptions are inherent in the estimation of future taxable income, including
factors such as future operating conditions and the assessment of the effects of
foreign taxes on our U.S. federal income taxes. Future operating conditions can
be affected by numerous factors, including (i) future crude oil and condensate,
NGLs and natural gas prices, (ii) estimated quantities of crude oil and
condensate, NGLs and natural gas, (iii) expected timing of production, and (iv)
future capital requirements. These assumptions are described in further detail
above regarding our impairment assessment of long-lived assets. An estimate of
the sensitivity to changes in assumptions resulting in future taxable income
calculations is not practicable, given the numerous assumptions that can
materially affect our estimates. Unfavorable adjustments to some of the above
listed assumptions would likely be offset by favorable adjustments in other
assumptions. For example, the impact of sustained reduced commodity prices on
future taxable income would likely be partially offset by lower capital
expenditures.
Based on the assumptions and judgments described above, as of December 31, 2020,
we reflect a valuation allowance in our consolidated balance sheet of $948
million against our gross deferred tax assets of $2.7 billion in various
jurisdictions in which we operate. Our gross deferred tax assets consist
primarily of federal U.S. operating loss carryforwards of $655 million, which
will expire in 2035 - 2037, and $1.1 billion which can be carried forward
indefinitely. Since December 31, 2016, we have maintained a full valuation
allowance on our net federal deferred tax assets. If objective negative evidence
in the form of cumulative losses are no longer present and additional weight is
given to subjective evidence such as forecasted projections of taxable income in
future years, we would adjust the amount of the federal deferred tax assets
considered realizable and reduce the provision for income taxes in the period of
adjustment. See Item 8. Financial Statements and Supplementary Data - Note 8
to the consolidated financial statements for further detail.
Pension and Other Postretirement Benefit Obligations
Accounting for pension and other postretirement benefit obligations involves
numerous assumptions, the most significant of which relate to the following:
•the discount rate for measuring the present value of future plan obligations;
•the expected long-term return on plan assets; and
•the rate of future increases in compensation levels.
We develop our demographics and utilize the work of third-party actuaries to
assist in the measurement of these obligations. We have selected different
discount rates for our U.S. pension plans and our other U.S. postretirement
benefit plans due to the different projected benefit payment patterns. In
determining the assumed discount rates, our methods include a review of market
yields on high-quality corporate debt and use of our third-party actuary's
discount rate model. This model calculates an equivalent single discount rate
for the projected benefit plan cash flows using a yield curve derived from bond
yields. The yield curve represents a series of annualized individual spot
discount rates from 0.5 to 99 years. The bonds used are rated AA or higher by a
recognized rating agency, only non-callable bonds are included and outlier bonds
(bonds that have a yield to maturity that significantly deviates from the
average yield within each maturity grouping) are removed. Each issue is required
to have at least $300 million par value outstanding. The constructed yield curve
is based on those bonds representing the 50% highest yielding issuances within
each defined maturity group.
The asset rate of return assumption for the funded U.S. plan considers the
plan's asset mix (currently targeted at approximately 55% equity and 45% other
fixed income securities), past performance and other factors. Certain components
of the asset mix are modeled with various assumptions regarding inflation, debt
returns and stock yields.
Compensation change assumptions are based on historical experience, anticipated
future management actions and demographics of the benefit plans. Health care
cost trend assumptions are developed based on historical cost data, the
near-term outlook and an assessment of likely long-term trends.
Item 8. Financial Statements and Supplementary Data - Note 20 to the
consolidated financial statements includes detailed information about the
assumptions used to calculate the components of our annual defined benefit
pension and other postretirement plan expense, as well as the obligations and
accumulated other comprehensive income reported on the consolidated balance
sheets.
Contingent Liabilities
We accrue contingent liabilities for environmental remediation, tax deficiencies
related to operating taxes, as well as tax disputes and litigation claims when
such contingencies are probable and estimable. Actual costs can differ from
estimates for many reasons. For instance, settlement costs for claims and
litigation can vary from estimates based on differing interpretations
50
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of laws, opinions on responsibility and assessments of the amount of damages.
Similarly, liabilities for environmental remediation may vary from estimates
because of changes in laws, regulations and their interpretation, additional
information on the extent and nature of site contamination and improvements in
technology. Our in-house legal counsel regularly assesses these contingent
liabilities. In certain circumstances outside legal counsel is utilized.
We generally record losses related to these types of contingencies as other
operating expense or general and administrative expense in the consolidated
statements of income, except for tax contingencies unrelated to income taxes,
which are recorded as taxes other than income (such as production, severance and
ad valorem taxes). For additional information on contingent liabilities, see
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations - Management's Discussion and Analysis of Environmental
Matters, Litigation and Contingencies .
An estimate of the sensitivity to net income if other assumptions had been used
in recording these liabilities is not practical because of the number of
contingencies that must be assessed, the number of underlying assumptions and
the wide range of reasonably possible outcomes, in terms of both the probability
of loss and the estimates of such loss.
Accounting Standards Not Yet Adopted
See Item 8. Financial Statements and Supplementary Data - Note 2 to the
consolidated financial statements.
51

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Market Closed - Nyse Other stock markets 04:00:02 2024-04-25 pm EDT			5-day change	1st Jan Change
27.74 ^USD	+0.76%		+1.24%	+14.82%

Apr. 24	Marathon Oil Keeps Quarterly Dividend at $0.11 a Share, Payable June 10 to Stockholders of Record May 15	MT
Apr. 22	Raymond James Adjusts Price Target on Marathon Oil to $40 From $32	MT

Marathon Oil Keeps Quarterly Dividend at $0.11 a Share, Payable June 10 to Stockholders of Record May 15	Apr. 24	MT
Raymond James Adjusts Price Target on Marathon Oil to $40 From $32	Apr. 22	MT
Piper Sandler Adjusts Price Target on Marathon Oil to $34 From $32	Apr. 19	MT
Sector Update: Energy Stocks Decline Late Afternoon	Apr. 18	MT
Bureau of Land Management Finalizes Public Lands Rule Over Opposition From Mining, Energy Companies	Apr. 18	MT
Marathon Oil Performance Driven by Rising Crude Prices, Debt Refinancing Makes Limited Impact, UBS Says	Apr. 18	MT
Wells Fargo Raises Price Target on Marathon Oil to $39 From $36	Apr. 17	MT
Tudor Pickering Holt Raises Price Target on Marathon Oil to $33 From $32	Apr. 16	MT
Jefferies & Co Adjusts Marathon Oil Price Target to $28 From $26	Apr. 15	MT
Siebert Williams Shank Adjusts Marathon Oil Price Target to $39 From $34, Buy Rating Kept	Apr. 15	MT
Morgan Stanley Lifts Price Target on Marathon Oil to $27 From $26, Keeps Equalweight Rating	Apr. 15	MT
UBS Raises Marathon Oil's Price Target to $32 From $27, Maintains Neutral Rating	Apr. 11	MT
Marathon Oil Gets Flexibility With $1.2 Billion Debt Offering to Extend Repayments, Cut Costs, UBS Says	Apr. 02	MT
Marathon Oil Insider Sold Shares Worth $997,887, According to a Recent SEC Filing	Mar. 28	MT
Sector Update: Energy Stocks Decline Pre-Bell Wednesday	Mar. 27	MT
Marathon Oil Prices Offering of Senior Notes Due 2029, 2034	Mar. 26	MT
Marathon Oil Insider Sold Shares Worth $1,981,619, According to a Recent SEC Filing	Mar. 26	MT
Marathon Oil Insider Sold Shares Worth $1,418,051, According to a Recent SEC Filing	Mar. 26	MT
Goldman Sachs Adjusts Marathon Oil's Price Target to $30 From $26.50, neutral	Mar. 26	MT
Mizuho Securities Raises Price Target on Marathon Oil to $31 From $28, Maintains Neutral Rating	Mar. 22	MT
Stifel Adjusts Price Target on Marathon Oil to $36 From $39, Maintains Buy Rating	Mar. 22	MT
Marathon Oil Insider Sold Shares Worth $2,172,719, According to a Recent SEC Filing	Mar. 21	MT
North American Morning Briefing : Inflation -2-	Mar. 15	DJ
Sector Update: Energy Stocks Advance Late Afternoon	Mar. 14	MT
Sector Update: Energy Stocks Rise in Thursday Afternoon Trading	Mar. 14	MT

	1st Jan change	Capi.
MARATHON OIL CORPORATION	+14.82%	15.73B
CHEVRON CORPORATION	+10.81%	302B
CONOCOPHILLIPS	+12.10%	151B
CNOOC LIMITED	+46.15%	118B
EOG RESOURCES, INC.	+11.91%	78B
PIONEER NATURAL RESOURCES COMPANY	+22.35%	64.37B
OCCIDENTAL PETROLEUM CORPORATION	+13.68%	59.69B
HESS CORPORATION	+11.99%	48.87B
DIAMONDBACK ENERGY, INC.	+33.54%	36.62B
WOODSIDE ENERGY GROUP LTD	-9.01%	35.2B

Marathon Oil Corporation

Equities

MRO

US5658491064

Oil & Gas Exploration and Production

MARATHON OIL : Management's Discussion and Analysis of Financial Condition and Results of Operations (form 10-K)

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