MARATHON OIL CORPORATION Executive Overview Outlook Operations Market Conditions Results of Operations Critical Accounting Estimates Accounting Standards Not Yet Adopted Cash Flows Liquidity and Capital Resources Environmental Matters and Other Contingencies The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the preceding consolidated financial statements and notes in Item 1 . Executive Overview We are an independent exploration and production company based inHouston, Texas . Our strategy is to deliver competitive and improving corporate level returns by focusing our capital investment in our lower cost, higher marginU.S. resource plays (Eagle Ford inTexas , Bakken inNorth Dakota , STACK and SCOOP inOklahoma andNorthern Delaware inNew Mexico ). Our reinvestment rate and 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. Keeping our workforce safe, minimizing our environmental impact, strong corporate governance and protecting our balance sheet are foundational to the execution of our strategy. Throughout the COVID-19 pandemic, we leveraged our emergency response protocols and business continuity plans to help manage our operations and workforce. Our workforce worked remotely for a significant period of time since the pandemic began. We implemented a process for a phased return of employees to the office last year and, duringApril 2021 , the majority of our corporate workforce returned to the office. Working remotely did not significantly impact our ability to maintain operations, allowed our field offices to operate without any disruption and did not cause us to incur significant additional expenses. Key highlights include the following: Maintained focus on balance sheet and liquidity •At the end of the third quarter 2021, we had approximately$3.6 billion of liquidity, comprised of an undrawn$3.1 billion revolving credit facility and$485 million in cash. We remain investment grade at all three primary rating agencies, with Moody's and Fitch recently upgrading their rating outlooks to stable and positive, respectively. •In the first nine months of 2021, we generated$2.1 billion of cash provided by operating activities, which substantially funded$1.4 billion of total debt redemption,$772 million of additions to property, plant and equipment and dividends of$94 million . •We continued our capital discipline through the third quarter as we are within our full-year capital budget of$1.0 billion . •Consistent with our strategy to enhance the balance sheet, inSeptember 2021 , we fully redeemed our outstanding$900 million 3.85% Senior Notes due 2025. See Note 16 to the consolidated financial statements and Liquidity and Capital Resources for further information. Financial and operational results •In the third quarter of 2021,U.S. net sales volumes decreased by 5% to 281 mboed, including a 3% reduction inU.S. crude oil net sales volumes compared to the same quarter last year as a result of overall lower drilling and completion activities and natural decline. •Our net income per share was$0.23 in the third quarter of 2021 as compared to a net loss per share of$0.40 in the 29 -------------------------------------------------------------------------------- same period last year. Included in our financial results for the current quarter: •Revenues from contracts with customers increased$677 million compared to the same quarter last year. We experienced significant increases in realized prices for crude oil and condensate, NGLs and natural gas. •Net loss on commodity derivatives of$79 million , as compared to a net loss of$1 million in 2020. The increase in derivative losses were a direct result of higher commodity prices. •Income from equity method investments of$86 million , an increase of$96 million from the same period in 2020. Our equity method investees realized higher prices in the current quarter whereas the same period in 2020 had lower realized prices and an impairment of$18 million . •A loss on the early redemption of debt totaling$102 million , which primarily represents the premium payment for the early redemption. Compensation and ESG Highlights and Initiatives •CEO andBoard 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. •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. •Adopted a medium-term goal for GHG emissions intensity reduction by 2025. •ContinuedBoard of Director refreshment with two Directors added during the first quarter of 2021, reflecting commitment to refreshment, independence, and diversity. Outlook Capital Budget InFebruary 2021 , we announced a 2021 capital budget of$1.0 billion , which is effectively a maintenance capital budget. Our maintenance-level capital budget has allowed 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 and we expect that strategy to drive our 2022 capital budget. The 2021 capital budget is weighted towards the fourU.S. resource plays with approximately 90% allocated to the Eagle Ford and Bakken. Operations The following table presents a summary of our sales volumes for each of our segments. Refer to Results of Operations for a price-volume analysis for each of the segments. Three Months Ended September 30, Nine Months Ended September 30, Increase Increase Net Sales Volumes 2021 2020 (Decrease) 2021 2020 (Decrease) United States (mboed) 281 297 (5) % 280 314 (11) % International (mboed) 61 71 (14) % 64 79 (19) % Total (mboed) 342 368 (7) % 344 393 (12) % United States Net sales volumes in the segment were lower in the third quarter of 2021 and the first nine months of 2021 as compared to their respective 2020 periods due to lower capital investment, timing of wells to sales, natural decline and midstream downtime. The decrease in capital investment is a direct result of the demand contraction, beginning in 2020, related to the global pandemic. We continue to expect that our planned pace of drilling and completions activity during the remainder of the year will enable us to meet our 2021 production guidance as noted in the preceding Outlook section. The following tables provide additional details regarding net sales volumes, sales mix and operational drilling activity for our significant operations within this segment: 30 --------------------------------------------------------------------------------
Three Months Ended September 30, Nine Months Ended September 30,
Increase Increase
Net Sales Volumes 2021 2020 (Decrease) 2021 2020 (Decrease)
Equivalent Barrels (mboed)
Eagle Ford 95 91 4 % 88 104 (15) %
Bakken 103 98 5 % 107 103 4 %
Oklahoma 55 73 (25) % 54 69 (22) %
Northern Delaware 21 27 (22) % 24 29 (17) %
Other United States 7 8 (13) % 7 9 (22) %
Total United States 281 297 (5) % 280 314 (11) %
Three Months Ended September 30, 2021
Sales Mix - U.S. Resource Plays Eagle Ford Bakken Oklahoma Northern Delaware Total
Crude oil and condensate 64 % 65 % 21 % 54 % 55 %
Natural gas liquids 19 % 22 % 34 % 22 % 23 %
Natural gas 17 % 13 % 45 % 24 % 22 %
Three Months Ended September 30, Nine Months Ended September 30,
Drilling Activity - U.S. Resource
Plays 2021 2020 2021 2020
Gross Operated
Eagle Ford:
Wells drilled to total depth 23 17 76 58
Wells brought to sales 29 9 99 67
Bakken:
Wells drilled to total depth 16 6 55 41
Wells brought to sales 27 8 46 41
Oklahoma:
Wells drilled to total depth - - - 9
Wells brought to sales 4 - 4 13
Northern Delaware:
Wells drilled to total depth - - - 15
Wells brought to sales 3 1 3 13
31--------------------------------------------------------------------------------
International
Net sales volumes were lower in the third quarter of 2021 and the first nine
months of 2021 as compared to their respective 2020 periods primarily due to
natural decline. The following table provides details regarding net sales
volumes for our operations within this segment:
Three Months Ended September 30, Nine Months Ended September 30,
Increase Increase
Net Sales Volumes 2021 2020 (Decrease) 2021 2020 (Decrease)
Equivalent Barrels (mboed)
Equatorial Guinea 61 71 (14) % 64 79 (19) %
Equity Method Investees
LNG (mtd) 3,119 3,960 (21) % 3,186 4,551 (30) %
Methanol (mtd) 1,218 1,065 14 % 1,137 996 14 %
Condensate and LPG (boed) 9,537 9,340 2 % 9,382 10,288 (9) %
Market Conditions
Commodity prices are the most significant factor impacting our revenues,
profitability, operating cash flows, the amount of capital we invest in our
business, redemption of our debt, 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. Beginning in December 2020 and
continuing through the first nine months of 2021, commodity prices continued to
increase due to rising oil demand as COVID-19 vaccination rates and global
economic activity increased. Higher commodity prices were also supported by
ongoing OPEC petroleum supply limitations and weather events in 2021 that
disrupted production. We continue to expect commodity price volatility given the
global dynamics of supply and demand that exist in the market. Refer to Item 1A.
Risk Factors in our 2020 Annual Report on Form 10-K for further discussion on
how declines in commodity prices could impact us.
32
--------------------------------------------------------------------------------The following table presents our average price realizations and the related benchmarks for crude oil and condensate, NGLs and natural gas for the third quarter and first nine months of 2021 and 2020.
Three Months Ended September 30, Nine Months Ended September 30,
Increase Increase
2021 2020 (Decrease) 2021 2020 (Decrease)
Average Price Realizations(a)
Crude oil and condensate (per bbl)(b) $ 69.40 $ 37.78 84 % $ 63.16 $ 34.82 81 %
Natural gas liquids (per bbl) 30.68 11.80 160 % 26.50 9.77 171 %
Natural gas (per mcf)(c) 4.17 1.78 134 % 4.35 1.61 170 %
Benchmarks
WTI crude oil average of daily prices
(per bbl) $ 70.52 $ 40.92 72 % $ 65.04 $ 38.21 70 %
Magellan East Houston ("MEH") crude
oil average of daily prices (per bbl) 71.64 41.59 72 % 66.03 38.93 70 %
Mont Belvieu NGLs (per bbl)(d) 32.27 15.87 103 % 27.08 13.77 97 %
Henry Hub natural gas settlement date
average (per mmbtu) 4.01 1.98 103 % 3.18 1.88 69 %
(a)Excludes gains or losses on commodity derivative instruments.
(b)Inclusion of realized gains (losses) on crude oil derivative instruments
would have decreased average price realizations by $4.00 per bbl and increased
average price realizations by $2.24 per bbl for the third quarter 2021 and 2020,
respectively. Inclusion of realized gain (losses) on crude oil derivative
instruments would have decreased average price realizations by $4.72 per bbl and
increased average price realizations by $1.74 per bbl for the first nine months
of 2021 and 2020, respectively.
(c)Inclusion of realized gains (losses) on natural gas derivative instruments
would have decreased average price realizations by $1.08 per mcf for the third
quarter 2021 and would have minimal impact on average price realizations for the
other periods presented.
(d)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 sold at reference to
Mont Belvieu prices.
Natural gas - A significant portion of our volumes are sold at bid-week prices,
or first-of-month indices relative to our producing areas.
International (E.G.)
The following table presents our average price realizations and the related
benchmark for crude oil for the third quarter and first nine months of 2021 and
2020.
Three Months Ended September 30, Nine Months Ended September 30,
Increase Increase
2021 2020 (Decrease) 2021 2020 (Decrease)
Average Price Realizations
Crude oil and condensate (per
bbl) $ 56.36 $ 30.28 86 % $ 51.54 $ 26.05 98 %
Natural gas liquids (per bbl) 1.00 1.00 - % 1.00 1.00 - %
Natural gas (per mcf) 0.24 0.24 - % 0.24 0.24 - %
Benchmark
Brent (Europe ) crude oil (per
bbl)(a) $ 73.47 $ 42.96 71 % $ 67.71 $ 40.92 65 %
(a)Average of monthly prices obtained from the United States Energy Information
Agency website.
Crude oil and condensate - Alba field liquids production is primarily
condensate. MEGPL and Marathon E.G. International Limited generally sell their
share of condensate 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 Unit Parties for distribution and sale to AMPCO and EG
LNG.
33
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Natural gas liquids - Wet gas is sold to Alba Plant LLC at a fixed-price long
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
Unit Parties 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.
Results of Operations
Three Months Ended September 30, 2021 vs. Three Months Ended September 30, 2020
Revenues from contracts with customers are presented by segment in the table
below:
Three Months Ended September 30,
(In millions) 2021 2020
Revenues from contracts with customers
United States $ 1,375 $ 722
International 63 39
Segment revenues from contracts with customers $
1,438
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.
Increase (Decrease) Related to
Three Months Ended Three Months Ended
(In millions) September 30, 2020 Price Realizations Net Sales Volumes September 30, 2021
United States Price/Volume Analysis
Crude oil and condensate $ 552 $ 448 $ (16) $ 984
Natural gas liquids 73 113 (3) 183
Natural gas 69 83 (8) 144
Other sales 28 64
Total $ 722 $ 1,375
International Price/Volume Analysis
Crude oil and condensate $ 31 $ 26 $ (1) $ 56
Natural gas liquids 1 - (1) -
Natural gas 7 - (1) 6
Other sales - 1
Total $ 39 $ 63
Net gain (loss) on commodity derivatives in the third quarter of 2021, was a
loss of $79 million , compared to a net loss of $1 million for the same period in
2020. 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 14 to the
consolidated financial statements for further information.
Income from equity method investments increased $96 million in third quarter of
2021 primarily due to higher price realizations coupled with an impairment of
$18 million to an investment in an equity method investee in third quarter of
2020. See Note 10 to the consolidated financial statements for more detail.
Production expenses increased $2 million in the third quarter of 2021 versus the
same period in 2020. Our U.S. and International segments production expense rate
increased due to lower sales volumes from natural decline.
The following table provides production expense and production expense rates
(expense per boe) for each segment:
34
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Three Months Ended
Increase Increase
($ in millions; rate in $ per boe) 2021 2020 (Decrease) 2021 2020 (Decrease)
Production Expense and Rate Expense Rate
United States $ 119 $ 118 1 % $ 4.59 $ 4.32 6 %
International $ 12 $ 11 9 % $ 2.17 $ 1.76 23 %
Shipping, handling and other operating increased $36 million in the third
quarter of 2021 versus the same period in 2020. As disclosed in our Form 10-K,
certain of our processing arrangements with midstream entities are
percentage-of-proceeds contracts. We classify the proceeds retained by the
midstream companies as shipping and handling cost. The increase in shipping and
handling costs of these percentage-of-proceeds contracts coincides with the
increase in realized natural gas liquids prices. In addition, higher marketing
costs contributed to the increase due to more volumes purchased for resale to
satisfy transportation commitments. This was partially offset by higher legal
expenses in third quarter of 2020.
Exploration expenses include unproved property impairments, dry well costs,
geological and geophysical and other costs. The increase in unproved property
impairments were primarily driven by our decision not to drill certain leases
related to resource exploration in the third quarter of 2021. The dry well costs
includes the write-off of suspended costs associated with drilled and
uncompleted wells primarily in Permian in the third quarter of 2021.
The following table summarizes the components of exploration expenses:
Three Months Ended
Increase
(In millions) 2021 2020 (Decrease)
Exploration Expenses
Unproved property impairments $ 48 $ 23 109 %
Dry well costs 14 - - %
Geological and geophysical - 2 (100) %
Other 1 2 (50) %
Total exploration expenses $ 63 $ 27 133 %
Depreciation, depletion and amortization decreased $32 million in the third
quarter of 2021 primarily as a result of lower sales volumes. Our segments apply
the units-of-production method to the majority of their assets, including
capitalized asset retirement costs; therefore volumes have an impact on DD&A
expense.
The DD&A rate (expense per boe) is impacted by field-level changes in reserves,
capitalized costs and sales volume mix between fields. The following table
provides DD&A expense and DD&A expense rates for each segment:
Three Months Ended
Increase Increase
($ in millions; rate in $ per boe) 2021 2020 (Decrease) 2021 2020 (Decrease)
DD&A Expense and Rate Expense Rate
United States $ 499 $ 530 (6) % $ 19.29 $ 19.39 (1) %
International $ 17 $ 19 (11) % $ 3.12 $ 2.89 8 %
Impairments increased $12 million in the third quarter of 2021 primarily due to
an $8 million impairment related to an increase in the estimated future
decommissioning costs of certain non-producing wells, pipelines and production
facilities and a $5 million impairment associated with our interests in outside
operated conventional assets located in New Mexico. See Note 10 , Note
11 , and Note 23 to the consolidated financial statements for more 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 increased $39 million primarily due
to higher price realizations in the U.S. segment in the third quarter of 2021.
General and administrative expenses increased $17 million in the third quarter
of 2021 as a result of increases in accruals for variable employee compensation
plans, commensurate with our improved financial performance.
35
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Loss on early extinguishment of debt increased $102 million due to make-whole
call provisions paid upon redemption of $900 million in senior unsecured notes
in the third quarter of 2021. See Note 16 to the consolidated financial
statements for further detail.
Provision (benefit) for income taxes reflects an effective income tax rate of 2%
in the third quarter of 2021, as compared to an effective income tax rate of
(2)% in the same period in 2020. See Note 6 to the consolidated financial
statements for a more detailed discussion concerning the rate changes.
Segment Income
Segment income represents income that 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, 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):
Three Months Ended September 30,
(In millions) 2021 2020
United States $ 305 $ (135)
International 93 8
Segment income (loss) 398 (127)
Items not allocated to segments, net of income taxes (214) (190)
Net income (loss) $ 184 $ (317)
United States segment income (loss) in the third quarter of 2021 was $305
million of income versus a $135 million loss for the same period in 2020. The
increase in income was primarily due to higher price realizations and lower DD&A
expenses. These favorable changes were partially offset by higher realized
losses on commodity derivatives, production taxes and shipping and handling in
the third quarter of 2021.
International segment income (loss) in the third quarter of 2021 was $93 million
of income versus $8 million of income for the same period in 2020, primarily due
to higher price realizations that yielded positive effects on both consolidated
operations and our equity method investees in the third quarter of 2021.
Results of Operations
Nine Months Ended September 30, 2021 vs. Nine Months Ended September 30, 2020
Revenues from contracts with customers are presented by segment in the table
below:
Nine Months Ended
September 30,
(In millions) 2021 2020
Revenues from contracts with customers
United States $ 3,696 $ 2,154
International 173 121
Segment revenues from contracts with customers Below is a price/volume analysis for each segment. Refer to Operations and
Market Conditions for additional detail related to our net sales volumes and average price realizations.
36
--------------------------------------------------------------------------------Increase (Decrease) Related to
Nine Months Ended Nine Months Ended
(In millions) September 30, 2020 Price Realizations Net Sales Volumes September 30, 2021
United States Price/Volume Analysis
Crude oil and condensate $ 1,741 $ 1,216 $ (246) $ 2,711
Natural gas liquids 161 272 (3) 430
Natural gas 190 283 (23) 450
Other sales 62 105
Total $ 2,154 $ 3,696
International Price/Volume Analysis
Crude oil and condensate $ 96 $ 75 $ (20) $ 151
Natural gas liquids 3 - (1) 2
Natural gas 22 - (4) 18
Other sales - 2
Total $ 121 $ 173
Net gain (loss) on commodity derivatives in the first nine months of 2021 was a
loss of $398 million , compared to a net gain of $131 million for the same period
in 2020. 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 14 to
the consolidated financial statements for further information.
Income (loss) from equity method investments increased $353 million for the
first nine months of 2021. We recognized impairments of $170 million related to
an investment in an equity method investee in the first nine months of 2020.
Additionally, we experienced higher price realizations in the first nine months
of 2021.
Production expenses for the first nine months of 2021 decreased by $40 million
compared to the same period in 2020, primarily as a result of the U.S. segment's
lower operational costs and continued cost management, specifically staffing and
contract labor.
The following table provides production expense and production expense rates for
each segment:
Nine Months Ended
Increase Increase
($ in millions; rate in $ per boe) 2021 2020 (Decrease) 2021 2020 (Decrease)
Production Expense and Rate Expense Rate
United States $ 343 $ 375 (9) % $ 4.49 $ 4.36 3 %
International $ 35 $ 43 (19) % $ 2.00 $ 2.00 - %
Shipping, handling and other operating expenses increased $106 million in the
first nine months of 2021 from the comparable 2020 period. As disclosed in our
Form 10-K, certain of our processing arrangements with midstream entities are
percentage-of-proceeds contracts. We classify the proceeds retained by the
midstream companies as shipping and handling cost. The increase in shipping and
handling costs of these percentage-of-proceeds contracts coincides with the
increase in realized natural gas liquids prices. In addition, higher marketing
costs contributed to the increase due to more volumes purchased for resale to
satisfy transportation commitments. This was partially offset by higher legal
expenses in the first nine months of 2020.
Exploration expenses include unproved property impairments, dry well costs,
geological and geophysical and other costs. The increase in unproved property
impairments were primarily driven by our decision not to drill certain leases
related to resource exploration in the third quarter of 2021. The dry well costs
include the write-off of suspended costs associated with drilled and uncompleted
wells primarily in Permian in the third quarter of 2021.
37
--------------------------------------------------------------------------------The following table summarizes the components of exploration expenses:
Nine Months Ended September 30,
(In millions) 2021 2020 Increase (Decrease)
Exploration Expenses
Unproved property impairments $ 85 $ 62 37 %
Dry well costs 16 1 1,500 %
Geological and geophysical 3 6 (50) %
Other 5 12 (58) %
Total exploration expenses $ 109 $ 81 35 %
Depreciation, depletion and amortization decreased $245 million in the first
nine months of 2021 from the comparable 2020 period, primarily as a result of
lower sales volumes in our U.S. and International segments. Our segments apply
the units-of-production method to the majority of their assets, including
capitalized asset retirement costs; therefore volumes have an impact on DD&A
expense.
The DD&A rate (expense per boe) is impacted by field-level changes in reserves,
capitalized costs and sales volume mix between fields. The following table
provides DD&A expense and DD&A expense rates for each segment:
Nine Months Ended September 30,
($ in millions; rate in $ per boe) 2021 2020 Increase (Decrease) 2021 2020 Increase (Decrease)
DD&A Expense and Rate Expense Rate
United States $ 1,477 $ 1,716 (14) % $ 19.33 $ 19.91 (3) %
International $ 54 $ 62 (13) % $ 3.10 $ 2.87 8 %
Impairments decreased $38 million in the first nine months of 2021. In 2020, we
impaired goodwill for $95 million related to our International reporting unit in
the first quarter of 2020. Impairments in 2021 consisted of a $30 million
impairment related to an increase in the estimated future decommissioning costs
of certain non-producing wells, pipelines and production facilities for
previously divested offshore assets located in the Gulf of Mexico and a $24
million impairment as we decommissioned certain Eagle Ford central facilities.
See Note 10 , Note 11 , and Note 23 to the consolidated financial
statements for discussion of the 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 increased $91 million primarily due
to higher price realizations in the U.S. segment in the first nine months of
2021.
Net interest and other decreased $66 million in the first nine months of 2021
versus the same period in 2020, primarily as a result of $57 million
mark-to-market gains on forward starting interest rate swaps in the first nine
months of 2021. See Note 14 to the consolidated financial statements for
further detail discussion of the interest rate swaps in the consolidated
financial statements.
General and administrative expenses increased $10 million in the first nine
months of 2021 versus the same period in 2020, primarily as a result of a
$13 million expense associated with the termination of an aircraft lease
agreement during the first quarter of 2021.
Loss on early extinguishment of debt increased $121 million due to make-whole
call provisions paid upon redemption of our $500 million 2022 Notes in the
second quarter of 2021 and our $900 million 2025 Notes in the third quarter of
2021. See Note 16 to the consolidated financial statements for further
detail.
Provision (benefit) for income taxes reflects an effective income tax rate of 7%
in the first nine months of 2021, as compared to an effective income tax rate of
1% in the same period in 2020. See Note 6 to the consolidated financial
statements for a more detailed discussion concerning the rate changes.
38
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Segment Income
Segment income represents income that 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, 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):
Nine Months Ended September 30,
(In millions) 2021 2020
United States $ 724 $ (520)
International 211 1
Segment income (loss) 935 (519)
Items not allocated to segments, net of income taxes (638) (594)
Net income (loss) $ 297 $ (1,113)
United States segment income (loss) for the first nine months of 2021 was $724
million of income versus a $520 million loss for the same period in 2020. This
increase was primarily due to higher price realizations and lower DD&A expenses.
These favorable changes were partially offset by lower sales volumes, realized
losses on commodity derivatives (as compared to realized gains in the prior
period), higher shipping and handling costs and production taxes in the first
nine months of 2021.
International segment income (loss) for the first nine months of 2021 was $211
million of income versus $1 million of income for the same period in 2020,
primarily due to higher price realizations in E.G. in the first nine months of
2021.
Critical Accounting Estimates
There have been no material changes or developments in the evaluation of the
accounting estimates and the underlying assumptions or methodologies pertaining
to our Critical Accounting Estimates disclosed in our Form 10-K for the year
ended December 31, 2020 .
Accounting Standards Not Yet Adopted
See Note 2 to the consolidated financial statements.
39
--------------------------------------------------------------------------------Cash Flows
Commodity prices are the most significant factor impacting our revenues,
profitability, operating cash flows, the amount of capital we invest in our
business, principal debt repayments, payment of dividends and funding of share
repurchases. As commodity prices increased during the first nine months of 2021,
we generated positive cash flow from operations. We continue to expect
volatility in commodity prices and that could impact how much cash flow from
operations we generate. The following table presents sources and uses of cash
and cash equivalents:
Nine Months Ended September 30,
(In millions) 2021 2020
Sources of cash and cash equivalents
Operating activities $ 2,093 $ 1,055
Borrowings - 400
Disposal of assets, net of cash transferred to the buyer 29 9
Other 15 7
Total sources of cash and cash equivalents $ 2,137 $ 1,471
Uses of cash and cash equivalents
Additions to property, plant and equipment $ (772) $ (1,090)
Additions to other assets - 15
Debt repayment (1,400) -
Debt extinguishment costs (117) -
Purchases of common stock (10) (92)
Dividends paid (94) (40)
Other (1) (3)
Total uses of cash and cash equivalents $
(2,394)
Cash flows generated from operating activities in the first nine months of 2021
were 98% higher compared to the same period in 2020, primarily as a result of
higher realized commodity prices. These were partially offset by net realized
losses on commodity derivatives (compared to realized gains in the prior
period), lower production volumes, and increased working capital usage.
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:
Nine Months Ended September 30,
(In millions) 2021 2020
United States $ 770 $ 874
International 4 -
Corporate 7 10
Total capital expenditures 781 884
Change in capital expenditure accrual (9) 206
Total use of cash and cash equivalents for property, plant and equipment
$ 772 The decline in our capital expenditures for theU.S. segment in the first nine months of 2021 compared to the same period in 2020 was caused by lower drilling and completions activities across all four of our resource plays. Liquidity and Capital Resources 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. AtSeptember 30, 2021 , we had approximately$3.6 billion of liquidity consisting of$485 million in cash and cash equivalents and$3.1 billion available under our revolving Credit Facility. 40 -------------------------------------------------------------------------------- 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, defined benefit plan contributions, repayment of debt maturities, dividends 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. 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. 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. See Item 1A. Risk Factors in our Annual Report on Form 10-K for the year endedDecember 31, 2020 for a discussion of how a downgrade in our credit ratings could affect us. OnOctober 27, 2021 , our Board of Directors approved a dividend of$0.06 per share payableDecember 10, 2021 to stockholders of record at the close of business onNovember 17, 2021 . Capital Resources Credit Arrangements and Borrowings InJune 2021 , we executed the sixth amendment to our unsecured Credit Facility. The primary changes resulting from this amendment are (i) increasing the size of the Credit Facility from$3.0 billion to$3.1 billion , (ii) extending the maturity of the commitments of certain consenting lenders fromMay 2023 toJune 2024 (with the remaining commitment of a single non-consenting lender to mature onMay 28, 2023 , at which time the size of the Credit Facility will be reduced to$3.0 billion ) and (iii) including certain other provisions and revisions, including provisions to provide for the eventual replacement of LIBOR as a benchmark interest rate. See Note 16 to the consolidated financial statements for further information. AtSeptember 30, 2021 , we had no borrowings against our Credit Facility and$4.0 billion of total long-term debt outstanding. InApril 2021 , we fully redeemed our outstanding$500 million 2.8% Senior Notes due 2022 and the redemption reduced annual cash interest expense by$14 million . As a result of the redemption, we incurred$19 million in costs related to a make-whole provision premium and the write off of unamortized discount and issuance costs in the second quarter of 2021. InSeptember 2021 , we fully redeemed our outstanding$900 million 3.85% 2025 Notes and the redemption reduced annual cash interest expense by approximately$35 million . As a result of the redemption, we incurred$102 million in costs related to a make-whole provision premium and the write off of unamortized discount and issuance costs in the third quarter of 2021. Our next significant long-term debt maturity is in the amount of$1.0 billion due 2027. Refer to our 2020 Annual Report on Form 10-K for a listing of our long-term debt maturities. In 2018, we signed an agreement with an owner/lessor to construct and lease a new build-to-suit office building inHouston, Texas . The lease commenced inSeptember 2021 , and as ofSeptember 30, 2021 , we estimate that project costs total approximately$302 million , including land acquisition and construction costs. See Note 12 to the consolidated financial statements for further information. Shelf Registration We have a universal shelf registration statement filed with theSEC under which we, as a "well-known seasoned issuer" for purposes ofSEC rules, have the ability to issue and sell an indeterminate amount of various types of debt and equity securities. Debt-To-Capital Ratio The Credit Facility includes a covenant requiring that our total debt to total capitalization ratio not exceed 65% as of the last day of the fiscal quarter. Our ratio was 20% and 26% atSeptember 30, 2021 andDecember 31, 2020 . 41 -------------------------------------------------------------------------------- Capital Requirements Share Repurchase Program No share repurchases were made under our share repurchases program during the nine months endedSeptember 30, 2021 . We did repurchase$10 million of shares during the nine months endedSeptember 30, 2021 related to our tax withholding obligation associated with the vesting of employee restricted stock awards. Subsequent to the quarter, we resumed our share repurchase program and repurchased approximately$200 million of shares of our common stock throughNovember 3, 2021 . EffectiveNovember 3, 2021 , our Board of Directors increased our remaining share repurchase program authorization from$1.1 billion to$2.5 billion . Contractual Cash Obligations As ofSeptember 30, 2021 , material decreases to our contractual cash obligations compared toDecember 31, 2020 include the redemption of our$500 million 2.8% Senior Notes due 2022 and$900 million 3.85% Senior Notes due 2025. See Note 16 to the consolidated financial statements for further information. Additionally, we had a material increase to our contractual cash obligations compared toDecember 31, 2020 associated with the increased guaranteed residual value of our Houston office building. See Note 12 to the consolidated financial statements for further information. Other than the items set forth above, there are no additional material changes to our consolidated cash obligations to make future payments under existing contracts, as disclosed in our 2020 Annual Report on Form 10-K. Environmental Matters and Other 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 we receive for 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. Other than the items set forth in Part II - Item 1. Legal Proceedings , there have been no significant changes to the environmental, health and safety matters under Item 1. Business or Item 3. Legal Proceedings in our 2020 Annual Report on Form 10-K. See Note 23 to the consolidated financial statements for a description of other contingencies. 42 -------------------------------------------------------------------------------- Forward-Looking Statements This Quarterly Report on Form 10-Q 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 (the "Exchange Act"). All statements, other than statements of historical fact, including without limitation statements regarding our future performance, business strategy, reserve estimates, asset quality, production guidance, drilling plans, capital plans, future debt retirement, cost and expense estimates, asset acquisitions and dispositions, tax allowances, future financial position and other plans and objectives for future cash flow from operations, are forward-looking statements. Words such as "anticipate," "believe," "continue," "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 we believe our assumptions concerning future events are reasonable, a number of factors could cause results to differ materially from those projected, including, but not limited to: •conditions in the oil and gas industry, including supply and 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 and economic conditions in theU.S. and E.G., including changes in foreign currency exchange rates, interest rates, and inflation rates; •actions taken by the members ofOPEC andRussia affecting the production and pricing of crude oil; and other global and domestic political, economic or diplomatic developments; •risks related to our hedging activities; •voluntary and involuntary volume curtailments; •delays or cancellations of certain drilling activities; •liability or corrective actions resulting from litigation or other proceedings and investigations; •capital available for exploration and development; •the inability of any party to satisfy closing conditions or delays in execution with respect to our asset acquisitions and dispositions; •drilling and operating risks; •lack of, or disruption in, access to storage capacity, pipelines or other transportation methods; •well production timing; •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 their contractual or legal obligations, including due to bankruptcy; •changes in our credit ratings; •hazards such as weather conditions, a health pandemic (including COVID-19), acts of war or terrorist acts and the governmental or military response thereto; •shortages of key personnel, including employees, contractors and subcontractors; •security threats, including cybersecurity threats and disruptions to our business and operations from breaches of our information technology systems, or breaches of the information technology systems, facilities and infrastructure of third parties with which we transact business; •changes in safety, health, environmental, tax and other regulations or requirements or initiatives including those 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 our 2020 Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and other filings with theSEC . All forward-looking statements included in this report are based on information available to us on the date of this report. Except as required by law, we undertake no obligation to revise or update any forward-looking statements as a result of new information, future events or otherwise. 43
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