MARATHON OIL CORPORATION Management's Discussion and Analysis provides a narrative on the Company's results of operations, financial condition and liquidity and capital resources on a historical basis and outlines the factors that have affected recent earnings, as well as those factors that are reasonably likely to affect future earnings. The following discussion and analysis should be read in conjunction with the information under Item 8. Financial Statements and Supplementary Data of this report and 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
•International - produces and markets crude oil and condensate, NGLs and natural gas outside ofthe 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, focused onU.S. resource plays:Eagle Ford inTexas , Bakken inNorth Dakota , STACK and SCOOP inOklahoma andNorthern Delaware inNew Mexico . OurU.S. assets are complemented by our international operations in E.G. Our overall business strategy is to responsibly deliver competitive corporate return levels, free cash flow and cash returns to shareholders, all of which are sustainable and resilient through long-term commodity price cycles. We expect to achieve our business strategy by adherence to a disciplined reinvestment rate capital allocation framework that limits our capital expenditures relative to our expected cash flow from operations. Keeping our workforce safe, maintaining a strong balance sheet, responsibly meeting global energy demand with a focus on continuously improving environmental performance, serving as a trusted partner in our local communities and maintaining best in-class corporate governance standards 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. Throughout the COVID-19 pandemic, we continue to leverage our emergency response protocols and business continuity plans to help manage our operations and workforce. Our corporate workforce worked remotely for a significant period of time when the pandemic began. In late 2020, we implemented a process for a phased return of employees to the office, 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 2021 highlights include:
Improved financial and operational results
•The significant increases in realized prices for crude oil and condensate, NGLs and natural gas resulted in:
•An increase of
•Increase in income from our equity method investments of
?Our equity investees' improved financial performance resulted in an increase of
?The prior year included impairments of
•A net loss on commodity derivatives of
•Partially offsetting the higher prices were increases in production taxes, shipping and handling costs and loss on early extinguishment of debt
•Production taxes increased
•Shipping and handling costs increased
•The$121 million loss on early extinguishment of debt primarily represents the premium payments for early redemptions during 2021, consistent with our balance sheet enhancement strategy
•Our net income per share was
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•Cash provided by operating activities was
•Our cash from operations totaled
Enhanced the balance sheet, increased return of capital to investors, preserved liquidity
•Reduced total debt outstanding by fully redeeming
•Our next significant long-term debt maturity is
•All three primary credit rating agencies continue to rate us as investment grade
•Increased return of capital to investors by:
•Repurchasing
•Distributing dividends totaling
•Delivered on our commitment to capital discipline with full-year 2021 capital
expenditures of
•Our
•Our
ESG Highlights and Initiatives
•Second best safety performance since Marathon became an independent E&P, as measured by Total Recordable Incident Rate for employees and contractors
•Continued to reduce GHG emissions intensity (relative to 2019 baseline) and improved total company gas capture during 2021
•Announced new environmental objectives for GHG intensity, methane intensity, and natural gas capture that complement existing 2025 GHG intensity goal
•Updated the short-term incentive scorecard with a renewed focus on safety performance, environmental performance (GHG emissions intensity), capital and operating efficiency, capital discipline/free cash flow generation and financial/balance sheet strength •Continued Board of Directors enhancement with two new Directors and a new Lead Director during 2021, reflecting commitment to refreshment, independence and diversity Outlook InFebruary 2022 , we announced a 2022 capital budget of$1.2 billion that prioritizes free cash flow generation over production growth, consistent with our disciplined capital allocation framework. We expect this maintenance-level capital budget will allow us to keep total company oil production in 2022 consistent with the oil production average from 2021.
The 2022 capital budget is weighted towards the four
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 2021 (Decrease) 2020 (Decrease) 2019
United States (mboed) 286 (7) % 306 (5) % 323
International (mboed)(a) 61 (21) % 77 (15) % 91
Total (mboed) 347 (9) % 383 (7) % 414
(a) We closed on the sale of 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.
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--------------------------------------------------------------------------------Net sales volumes in the segment were lower during the year endedDecember 31, 2021 due to lower capital investment, timing of wells to sales, natural decline and third-party midstream downtime. The decrease in capital investment is a direct result of the demand contraction, beginning in 2020 related to the global pandemic, coupled with our strategic goals of enhancing the balance sheet and return of capital to investors. 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 2021 (Decrease) 2020 (Decrease) 2019 Equivalent Barrels (mboed) Eagle Ford 89 (10) % 99 (7) % 106 Bakken 112 7 % 105 2 % 103 Oklahoma 54 (18) % 66 (15) % 78 Northern Delaware 23 (15) % 27 (4) % 28 Other United States 8 (11) % 9 13 % 8 Total United States 286 (7) % 306 (5) % 323 Sales Mix - U.S. Resource Plays - 2021 Eagle Ford Bakken Oklahoma Northern Delaware Total Crude oil and condensate 65% 66% 23% 56% 56% Natural gas liquids 17% 20% 32% 21% 22% Natural gas 18% 13% 45% 23% 22% Drilling Activity - U.S. Resource Plays 2021 2020 2019 Gross Operated Eagle Ford: Wells drilled to total depth 91 88 127 Wells brought to sales 117 87 146 Bakken: Wells drilled to total depth 72 63 73 Wells brought to sales 71 64 105 Oklahoma: Wells drilled to total depth - 9 68 Wells brought to sales 8 13 69 Northern Delaware: Wells drilled to total depth - 15 51 Wells brought to sales 7 19 54 35
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International
Net sales volumes in the segment were lower during the year ended
Increase Increase
Net Sales Volumes 2021 (Decrease) 2020 (Decrease) 2019
Equivalent Barrels (mboed)
Equatorial Guinea 61 (21) % 77 (9) % 85
United Kingdom(a) - - % - (100) % 5
Other International - - % - (100) % 1
Total International 61 (21) % 77 (15) % 91
Equity Method Investees
LNG (mtd) 2,941 (31) % 4,289 (13) % 4,933
Methanol (mtd) 1,046 3 % 1,017 (6) % 1,082
Condensate and LPG (boed) 8,560 (17) % 10,288 (7) % 11,104
(a) During 2019, we closed on the sale of our
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 followingOPEC's decision to increase production. A revisedOPEC deal to reduce production was agreed early in the second quarter of 2020 and prices partially recovered through the end of the year. Beginning inDecember 2020 and continuing through 2021, commodity prices continued to increase due to rising oil demand as global economic activity increased. Higher commodity prices were also supported by ongoingOPEC 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, including potential geopolitical events. 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. 36 --------------------------------------------------------------------------------
The following table presents our average price realizations and the related
benchmarks for crude oil and condensate, NGLs and natural gas for 2021, 2020 and
2019.
Increase Increase
2021 (Decrease) 2020 (Decrease) 2019
Average Price Realizations(a)
Crude oil and condensate (per bbl)(b) $ 66.88 86 % $ 35.93 (36) % $ 55.80
Natural gas liquids (per bbl)(c) 28.89 156 % 11.28 (21) % 14.22
Natural gas (per mcf)(d) 4.57 158 % 1.77 (19) % 2.18
Benchmarks
WTI crude oil average of daily prices (per bbl)$ 68.11 73 %$ 39.34 (31) %$ 57.04 MagellanEast Houston ("MEH") crude oil average of daily prices (per bbl) 69.25 73 % 39.95 (36) % 61.96 Mont Belvieu NGLs (per bbl)(e) 29.17 99 % 14.69 (18) % 17.81Henry Hub natural gas settlement date average (per mmbtu) 3.84 85 % 2.08 (21) % 2.63 (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$4.76 per bbl for 2021 and increased average price realizations by$2.14 per bbl and$0.67 per bbl for 2020 and 2019, respectively. (c)Inclusion of realized gains (losses) on NGL derivative instruments would have decreased average price realizations by$1.86 per bbl for 2021 and would have had a minimal impact on average price realizations for 2020. We did not have any NGL derivative instruments during 2019. (d)Inclusion of realized gains (losses) on natural gas derivative instruments would have decreased average price realizations by$0.56 per mcf for 2021 and would have had a minimal impact on average price realizations for the other periods presented. (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
Natural gas - A significant portion of volumes are sold at bid-week prices, or first-of-month indices relative to our producing areas.
International
The following table presents our average price realizations and the related benchmark for crude oil for 2021, 2020 and 2019.
Increase Increase
2021 (Decrease) 2020 (Decrease) 2019
Average Price Realizations
Crude oil and condensate (per bbl) $ 57.46 103 % $ 28.36 (47) % $ 53.09
Natural gas liquids (per bbl) 1.00 - % 1.00 (29) % 1.40
Natural gas (per mcf) 0.24 - % 0.24 (27) % 0.33
Benchmark
Brent (Europe) crude oil (per bbl)(a)$ 70.68 69 %$ 41.76 (35) %$ 64.36
(a) Average of monthly prices obtained from the
Crude oil and condensate - Generally sold in relation to the Brent crude
benchmark. We closed on the sale of our
37
--------------------------------------------------------------------------------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 from the Alba field under a fixed-price long term contract.Alba Plant LLC extracts NGLs and secondary condensate which is then sold byAlba 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. Natural gas liquids - Wet gas is sold toAlba 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 fromAlba Plant LLC being reflected in the income from equity method investments on the consolidated statements of income. Natural gas - Dry natural gas, processed byAlba Plant LLC on behalf of the Alba Unit Parties, is sold by the Alba Unit 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.Alba Plant LLC and EG LNG process third party gas under a combination of a tolling and a market linked profit-sharing arrangement, the benefits of which are included in our respective share of income from equity method investees.
Consolidated Results of Operations: 2021 compared to 2020
Revenues from contracts with customers are presented by segment in the table
below:
Year Ended December 31,
(In millions) 2021 2020
Revenues from contracts with customers
United States $ 5,334 $ 2,924
International 267 173
Segment revenues from contracts with customers$ 5,601
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
Year Ended Net Sales Year Ended
(In millions) December 31, 2020 Price Realizations Volumes December 31, 2021
United States Price/Volume Analysis
Crude oil and condensate $ 2,322 $ 1,817 $ (214) $ 3,925
Natural gas liquids 243 397 13 653
Natural gas 275 386 (29) 632
Other sales 84 124
Total $ 2,924 $ 5,334
International Price/Volume Analysis
Crude oil and condensate $ 140 $ 122 $ (22) $ 240
Natural gas liquids 4 - (2) 2
Natural gas 29 - (6) 23
Other sales - 2
Total $ 173 $ 267
Net gain (loss) on commodity derivatives in 2021 was a net loss of $383 million ,
compared to a net gain of $116 million in 2020. We have multiple crude oil, NGL
and natural gas 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.
38-------------------------------------------------------------------------------- Income (loss) from equity method investments increased$414 million in 2021 from 2020. Our investees benefited from higher price realizations in 2021. Also, we recognized impairments of$171 million related to an investment in an equity method investee in 2020; there were no such impairments in 2021. Net gain (loss) on disposal of assets in 2021 was a net loss of$19 million , compared to a net gain of$9 million in 2020. In 2021, we recognized a$20 million pre-tax loss related to a previously divested non-core conventional asset and a$12 million pre-tax loss associated with a reduction in our ownership interest in one of our equity method investees. See Note 24 to the consolidated financial statements for further detail regarding the reduction in ownership. Production expenses decreased$21 million during 2021 from 2020, primarily as a result of theU.S. segment's continued cost management, specifically staffing and contract labor. This was partially offset by timing of project activity. OurU.S. and International segments production expense rates increased due to lower sales volumes.
The following table provides production expense and production expense rates for each segment:
(In millions; rate in $ per boe) 2021 2020
Increase (Decrease) 2021 2020 Increase (Decrease) Production Expense and Rate
Expense Rate
United States $ 480 $ 494 (3) % $ 4.60 $ 4.42 4 %
International $ 54 $ 59 (8) % $ 2.45 $ 2.12 16 %
Shipping, handling and other operating expenses increased $131 million in 2021
from 2020. 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 costs. 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 as we purchased additional volumes for resale
to satisfy transportation commitments. This was partially offset by lower legal
expenses in 2021.
Exploration expenses include unproved property impairments, dry well costs,
geological and geophysical and other costs. The decrease in unproved property
impairments was primarily driven by a $78 million impairment of unproved
property leases in Louisiana Austin Chalk in our U.S. 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. See Note 12 to the consolidated financial
statements for discussion on the impairment in further detail. We also incurred
approximately $20 million less expense related to amortization of insignificant
unproved property lease balances in 2021. Finally, dry well costs for 2021
include an impairment of suspended costs associated with drilled and uncompleted
wells, primarily in the Permian, due to a change in our plan of development.
The following table summarizes the components of exploration expenses:
Year Ended December 31,
(In millions) 2021 2020 Increase (Decrease)
Exploration Expenses
Unproved property impairments $ 92 $ 157 (41) %
Dry well costs 33 2 1,550 %
Geological and geophysical 5 6 (17) %
Other 6 16 (63) %
Total exploration expenses $ 136 $ 181 (25) %
Depreciation, depletion and amortization decreased $250 million in 2021 from
2020, primarily as a result of lower sales volumes in our U.S. and International
segments. Our segments apply the units-of-production method to 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 affected 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:
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Increase Increase
(In millions; rate in $ per boe) 2021 2020 (Decrease) 2021 2020 (Decrease)
DD&A Expense and Rate Expense Rate
United States $ 1,972 $ 2,211 (11) % $ 18.90 $ 19.76 (4) %
International $ 68 $ 82 (17) % $ 3.07 $ 2.89 6 %
Impairments decreased $84 million in 2021 from 2020. Impairments in 2021
included $30 million 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 $24 million related to certain decommissioned Eagle Ford central facilities.
In 2020, impairments consisted 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 Note 12 , Note 13 , and Note 26 to the consolidated
financial statements for discussions of these 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 by $145 million in 2021
from 2020 period primarily due to higher price realizations in the U.S. segment
in 2021.
Net interest and other decreased $68 million in 2021 versus 2020, primarily as a
result of gains on our forward interest rates swaps. We recognized $54 million
of cumulative gains within Net interest and other during 2021 related to our
interest rate swaps as compared to $12 million of gains in 2020. Additionally,
our interest expense decreased as a result of our early extinguishment of debt
in 2021. See Note 1 6 to the consolidated financial statements for
further discussion of the interest rate swaps.
General and administrative expenses increased
Loss on early extinguishment of debt was$121 million for 2021, as compared to$28 million for 2020. The loss in 2021 was incurred upon redemption of our$500 million 2.8% Senior Notes due 2022 and$900 million 3.85% Senior Notes due 2025 in the second and third quarters of 2021, respectively. See Note 18 to the consolidated financial statements for further detail. Provision (benefit) for income taxes reflects an effective income tax rate of 6% for 2021, as compared to an effective income tax rate of 1% for 2020. See Note 8 to the consolidated financial statements for a discussion of the effective income tax rate.
Segment Results: 2021 compared to 2020
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, unrealized gains or losses on commodity derivative
instruments, gains or losses on interest rate derivative instruments, effects of
pension settlements and curtailments, or other items (as determined by the chief
operating decision maker (CODM)) are not allocated to operating segments.
40
--------------------------------------------------------------------------------The following table reconciles segment income (loss) to net income (loss):
Year Ended December 31,
(In millions) 2021 2020
United States $ 1,277 $ (553)
International 317 30
Segment income (loss) 1,594 (523)
Items not allocated to segments, net of income taxes(a) (648) (928)
Net income (loss) $ 946 $ (1,451)
(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 2021 was $1.3 billion of income versus a
$553 million loss 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 higher production taxes in 2021.
International segment income (loss) in 2021 was $317 million of income versus
$30 million of income in 2020, primarily due to higher price realizations in
E.G. in 2021 in our consolidated operations and our equity method investees.
Consolidated Results of Operations: 2020 compared to 2019
A detailed discussion of the year-over-year changes from the year endedDecember 31, 2020 toDecember 31, 2019 can be found in the Management's Discussion and Analysis section of our Annual Report on Form 10-K for the year endedDecember 31, 2020 and is available via theSEC's website at www.sec.gov and on our website at www.marathonoil.com.
Management's Discussion and Analysis of Financial Condition, Cash Flows and Liquidity
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 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. As previously discussed in the Outlook section, our capital budget for 2022 is$1.2 billion . Our top priorities for using cash provided by operations are to fund our capital budget, dividends and share repurchases, 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 business across a wide range of commodity price environments.
Cash Flows
The following table presents sources and uses of cash and cash equivalents for 2021 and 2020:
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Year Ended December 31,
(In millions) 2021 2020
Sources of cash and cash equivalents
Operating activities $ 3,239 $ 1,473
Borrowings - 400
Disposal of assets, net of cash transferred to the buyer 22 18
Equity method investments - return of capital 61 7
Other 1 1
Total sources of cash and cash equivalents $ 3,323 $ 1,899
Uses of cash and cash equivalents
Additions to property, plant and equipment $ (1,046) $ (1,343)
Additions to other assets - 15
Acquisitions, net of cash acquired (47) (1)
Purchases of common stock (734) (92)
Debt repayments (1,400) (500)
Debt extinguishment costs (117) (27)
Dividends paid (141) (64)
Other - (3)
Total uses of cash and cash equivalents $
(3,485)
Cash flows generated from operating activities in 2021 were 120% higher compared
to 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 prior period) and the impact from lower production volumes.
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) 2021 2020
United States $ 1,018 $ 1,137
International - 1
Corporate 14 13
Total capital expenditures 1,032 1,151
Change in capital expenditure accrual 14 192
Total use of cash and cash equivalents for property, plant and
equipment $ 1,046 $ 1,343
The decline in our capital expenditures for the U.S. segment in 2021 compared to
2020 was caused by lower drilling and completions activities across all four of
our resource plays.
42
--------------------------------------------------------------------------------Liquidity and Capital Resources
Capital Resources and 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. AtDecember 31, 2021 , we had approximately$3.7 billion of liquidity consisting of$580 million in cash and cash equivalents and$3.1 billion available under our revolving Credit Facility. 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. 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. 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 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.
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 28, 2023 toJune 21, 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 back down to$3.0 billion ) and (iii) including certain other provisions and revisions, including provisions provide for the eventual replacement of LIBOR as a benchmark interest rate. The Credit Facility includes a single financial covenant requiring that our ratio of total debt to total capitalization (debt-to-capital ratio) not exceed 65% as of the last day of each fiscal quarter. Our total debt-to-capital ratio was 20% atDecember 31, 2021 . See Item 8. Financial Statements and Supplementary Data - Note 18 to the consolidated financial statements for further information.
As of
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. Capital Requirements
Our material cash requirements include the following contractual and other obligations:
Capital Spending
See the Cash Flows section above for discussion around our 2021 capital
expenditures. Our approved capital budget for 2022 is
43
--------------------------------------------------------------------------------Debt
InApril 2021 , we fully redeemed our outstanding$500 million 2.8% Senior Notes due 2022 and the redemption will reduce 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% Senior Notes due 2025 and the redemption will reduce annual cash interest expense by approximately$35 million . As a result of the redemption, we incurred$102 million in costs related to the 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. See Item 8. Financial Statements and Supplementary Data - Note 18 to the consolidated financial statements for details regarding future debt maturities. Anticipated cash payments for interest in future periods are$197 million for 2022,$364 million for 2023-2024,$331 million for 2025-2026 and$1.3 billion for the remaining years for a total of$2.2 billion .
Share Repurchase Program
In the fourth quarter of 2021, we resumed our share repurchase program and repurchased$724 million of shares of our common stock. EffectiveNovember 3, 2021 , our Board of Directors increased our remaining share repurchase program authorization from$1.1 billion to$2.5 billion . As ofDecember 31, 2021 ,$1.9 billion of share repurchase program authorization remains. Additionally, we repurchased$10 million of shares during 2021 related to our tax withholding obligation associated with the vesting of employee restricted stock awards.
Subsequent to
Leases
In 2018, we signed an agreement with an owner/lessor to construct and lease a new build-to-suit office building inHouston, Texas . Construction was completed and the lease commenced inSeptember 2021 . See Item 8. Financial Statements and Supplementary Data - Note 14 to the consolidated financial statements for further information related to the building lease.
For future lease obligations, see Item 8. Financial Statements and Supplementary Data - Note 14 to the consolidated financial statements.
Dividends During 2021, we paid dividends totaling$141 million . OnJanuary 26, 2022 , our Board of Directors approved a dividend of$0.07 per share for the fourth quarter of 2021. The dividend is payable onMarch 10, 2022 to shareholders of record onFebruary 16, 2022 .
Pension and Postretirement Plans
Estimated cash payments for our pension and other postretirement benefits plans in future periods are$39 million for 2022,$68 million for 2023-2024,$57 million for 2025-2026 and$178 million for the remaining years for a total of$342 million . 44 --------------------------------------------------------------------------------
Other Cash Obligations
The table below provides aggregated information on our consolidated obligations
to make future payments under existing contracts as of
2023- 2025- Later
(In millions) Total 2022 2024 2026 Years
Purchase obligations:
Oil and gas activities $ 16 $ 7 $ 1 $ 2 $ 6
Service and materials contracts(a) 79 63 16 - -
Transportation and marketing
commitments(b) 1,503 234 448 407 414
Other 12 11 1 - -
Total purchase obligations 1,610 315 466 409 420
Other long-term liabilities reported in
the consolidated balance sheet 10 - 8 - 2
Total other contractual cash
obligations(c) $ 1,620 $ 315 $ 474 $ 409 $ 422
(a)Includes contracts to purchase services such as utilities, supplies and
various other maintenance and operating services..
(b)These obligations consist of firm capacity on third-party pipelines, minimum
volume throughput and firm purchase commitments.
(c)This table does not include the estimated discounted liability for
dismantlement, abandonment and restoration costs of oil and gas properties of
$316 million . See Item 8. Financial Statements and Supplementary Data - Note
13 to the consolidated financial statements.
Transactions with Related Parties
Offshore E.G., we own a 64% working interest in the Alba Unit. Onshore E.G., we own a 52% interest in an LPG processing plant, a 56% 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 Unit 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 theU.S. We had no material off-balance sheet arrangements forDecember 31, 2021 , 2020 and 2019.
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, litigation and contingencies that impact us, or could impact us, see Item 1. Business - Environmental, Health and Safety Matters , Item 1A. Risk Factors , Item 3. Legal Proceeding s and Item 8 . Financial Statements and Supplementary Data - Note 26 .
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--------------------------------------------------------------------------------Critical Accounting Estimates
The preparation of financial statements in accordance with accounting principles generally accepted in theU.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 and sufficient proved developed locations establish the reasonable certainty criteria required for booking proved reserves. As perSEC 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. Reserve estimates are based on an unweighted average of commodity prices in the prior 12-month period using the closing prices on the first day of each month, as defined by theSEC . The table below provides the 2021SEC pricing for certain benchmark prices: 2021 SEC Pricing WTI crude oil (per bbl) $ 66.56 Henry Hub natural gas (per mmbtu) $ 3.60 Brent crude oil (per bbl) $ 69.47 Mont Belvieu NGLs (per bbl) $ 28.57
When determining the
If the future average crude oil prices are below the average prices used to determine proved reserves atDecember 31, 2021 , 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 2021 proved reserves based on 2021 production. 46 -------------------------------------------------------------------------------- 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$ (1.72) $ 179$ 2.10 $ (219) International$ (0.28) $ 6$ 0.34 $ (8)
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. 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
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--------------------------------------------------------------------------------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 andOPEC 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 Part I. Item 1A. Risk Factor s 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.
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 ofDecember 31, 2021 our estimated undiscounted cash flows relating to our remaining long-lived assets significantly exceeded their carrying values. During 2021, we recorded impairment charges totaling$131 million related to proved and certain unproved properties. See Item 8. Financial Statements and Supplementary Data - Note 7 , Note 12 and Note 17 to the consolidated financial statements for discussion of impairments recorded in 2021, 2020 and 2019 and the related fair value measurements.
Impairment Assessment of Equity Method Investments
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 andOPEC 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 48 -------------------------------------------------------------------------------- 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 ourAlba Field . Our equity method investees currently process hydrocarbons from ourAlba Field , which consists of condensate, NGLs and natural gas reserves. Estimated quantities of hydrocarbons processed from ourAlba 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 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.
During 2021, we had no impairments related to our equity method investments. See Item 8. Financial Statements and Supplementary Data - Note 12 to the consolidated financial statements for further information regarding the impairment recognized during 2020.
Impairment Assessments of
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. See Item 8. Financial Statements and Supplementary Data - Note 15 to the consolidated financial statements for information regarding the$95 million full impairment of our goodwill in 2020.
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
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--------------------------------------------------------------------------------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 ofDecember 31, 2021 and 2020.
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 ourU.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 withU.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 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 ourU.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 ofDecember 31, 2021 , we reflect a valuation allowance in our consolidated balance sheet of$780 million against our gross deferred tax assets of$2.3 billion in various jurisdictions in which we operate. Our gross deferred tax assets consist primarily of federalU.S. operating loss carryforwards of$295 million , which will expire in 2036 - 2037, and$1.1 billion which can be carried forward indefinitely. SinceDecember 31, 2016 , we have maintained a full valuation allowance on our net federal deferred tax assets. We intend to continue a full valuation allowance on these deferred tax assets until there is sufficient evidence to support the reversal of all or some portion of the allowance. However, if current commodity prices are sustained and absent any additional objective negative evidence, we expect it is reasonably possible that sufficient positive evidence will exist within the next 12 months to adjust our current valuation allowance position. Exact timing and amount of the adjustment to the valuation allowance is unknown at this time. See Item 8. Financial Statements and Supplementary Data - Note 8 to the consolidated financial statements for further detail. 50
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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 estimate of demographic effects and utilize the work of third-party actuaries to assist in the measurement of these obligations. We have selected different discount rates for ourU.S. pension plans and our otherU.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 fundedU.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.
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 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.
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