SOUTHWESTERN ENERGY COMPANY Management's Discussion and Analysis is the Company's analysis of its financial performance and of significant trends that may affect future performance. It should be read in conjunction with the financial statements and notes, and supplemental oil and gas disclosures included elsewhere in this report. It contains forward-looking statements including, without limitation, statements relating to the Company's plans, strategies, objectives, expectations and intentions that are made pursuant to the "safe harbor" provisions of the Private Securities Litigation Reform Act of 1995. In many cases you can identify forward-looking statements by words such as "anticipate," "intend," "plan," "project," "estimate," "continue," "potential," "should," "could," "may," "will," "objective," "guidance," "outlook," "effort," "expect," "believe," "predict," "budget," "projection," "goal," "forecast," "target" or similar words. Unless required to do so under the federal securities laws, the Company does not undertake to update, revise or correct any forward-looking statements, whether as a result of new information, future events or otherwise. Readers are cautioned that such forward-looking statements should be read in conjunction with the Company's disclosures under the heading: " Cautionary Statement about Forward-Looking Statements " in this Annual Report. Also, see the risk factors and other cautionary statements described under the heading " Risk Factors
"
in Item 1A of this Annual Report.
OVERVIEWBackground
We are an independent energy company engaged in natural gas, oil and NGLs exploration, development and production, which we refer to as "E&P." We are also focused on creating and capturing additional value through our marketing business, which we call "Marketing". We conduct most of our businesses through subsidiaries, and we currently operate exclusively in the Appalachian andHaynesville natural gas basins in the lower 48 United States. E&P. Our primary business is the exploration for and production of natural gas as well as associated NGLs and oil, with our ongoing operations focused on the development of unconventional natural gas reservoirs located inPennsylvania , WestVirginia, Ohio andLouisiana . Our operations inPennsylvania ,West Virginia andOhio , which we refer to as "Appalachia," are focused on theMarcellus Shale , theUtica and the Upper Devonian unconventional natural gas and liquids reservoirs. Our operations inLouisiana , which we refer to as "Haynesville ," are primarily focused on theHaynesville andBossier natural gas reservoirs. We also have drilling rigs located in Appalachia andHaynesville , and we provide certain oilfield products and services, principally serving our E&P operations through vertical integration. In just over a year, we have completed three strategic acquisitions which have added scale to our operations and have laid the foundation for our future: •OnNovember 13, 2020 , we closed on the Montage Merger, which increased our footprint inWest Virginia andPennsylvania and expanded our operations intoOhio .
•On
•On
The Indigo Merger and GEPH Merger are the result of our strategy to diversify our operations by expanding our portfolio beyond Appalachia into theHaynesville andBossier formations, giving us additional exposure to the LNG corridor and other markets on theU.S. Gulf Coast . This expansion lowered our enterprise business risk, expanded our economic inventory, opportunity set and business optionality and enabled immediate cost structure savings. See Note 2 to the consolidated financial statements of this Annual Report for more information on the Mergers.
Marketing. Our marketing activities capture opportunities that arise through the marketing and transportation of natural gas, oil, and NGLs primarily produced in our E&P operations.
Focus in 2021. We took several steps in late 2020 and throughout 2021 towards achieving our strategic objectives of increasing scale in our operations, improving our margins, generating free cash flow and reducing our debt leverage metrics. We began the year having completed our first strategic business merger with the acquisition of Montage, which expanded our natural gas and liquids production footprint in Appalachia. During 2021, we completed two additional strategic mergers with the acquisitions of Indigo and GEPH, which diversified our asset portfolio into theHaynesville andBossier formations ofLouisiana with access to the LNG corridor and otherU.S. Gulf Coast markets. Recovering commodity prices during 2021 along with the increase in production volumes primarily associated with the Mergers, combined with our continued capital discipline to invest at levels which are designed to maintain our daily production consistent with the end of the prior year, have accelerated the generation of free cash flow. Through our disciplined capital investing, the Mergers have already had, and are expected to continue to have, a positive impact on our business and financial results by producing free cash flow, which we expect to use to pay down debt, resulting in the strengthening of our balance sheet and improvement in our debt leverage metrics. 54
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During 2021, we were also able to successfully finance the Indigo Merger and the GEPH Merger while also reducing our revolver balance and re-financing and extending our debt maturities on a large portion of our near-term senior notes at more favorable interest rates. These financings lowered our overall cost of debt and extended our weighted-average time to maturity. Generating free cash flow is an important part of our strategy to strengthen our balance sheet, and our long-term goal is to incorporate a cash return component into our overall economic return for shareholders. Our near-term strategic goal is to utilize our free cash flow to reduce our debt, thereby improving our leverage metrics and financial strength. As we approach our target leverage ratio and total debt ranges, we intend to expand our uses of free cash flow to include the return of capital to our shareholders. Free cash flow is a non-GAAP financial measure. We define free cash flow as net cash provided by operating activities, adjusted for (i) changes in assets and liabilities and (ii) cash transaction costs associated with mergers and restructuring, less capital investments. Free cash flow is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We believe free cash flow can provide an indicator of excess cash flow available to a company for the repayment of debt or for other general corporate purposes, as it disregards the timing of settlements of operating assets and liabilities. Natural gas, oil and NGL price fluctuations present challenges to our industry and our Company, as do changes in laws, regulations and investor sentiment and other key factors described under "Risk Factors" in Item 1A of this Annual Report. Although we currently expect to maintain a rolling three-year derivative portfolio, there can be no assurance that we will be able to add derivative positions to cover our expected production at favorable prices. See "Quantitative and Qualitative Disclosures About Market Risk" in Item 7A and
Note 6 - Derivatives and Risk Management , in the consolidated financial statements included in this Annual Report for further details.
Recent Financial and Operating Results
Significant operating and financial highlights for 2021 include:
•Completion of the mergers with Indigo on
•Net loss of$25 million , or ($0.03 ) per diluted share, improved from a net loss of$3,112 million , or$(5.42) per diluted share, in 2020. Net loss improved as a$5,506 million increase in operating income was partially offset by a$2,660 million reduction resulting from the impact of improved forward pricing on our derivatives position,$806 million of which was unrealized. Excluding the change in derivatives position, the($2,825) million change in non-cash ceiling test impairments and the($409) million change in our deferred tax provision recorded 2020, net income increased$2,513 million for 2021, as compared to 2020, primarily as a$2,681 million improvement in operating income was only partially offset by a$128 million change in loss on debt retirement and a$42 million increase in interest expense. •Operating income was$2,635 million for the year endedDecember 31, 2021 , compared to an operating loss of$2,871 million in 2020. Operating loss in 2020 included$2,825 million in non-cash full cost ceiling impairments. Excluding the non-cash impairments, operating income increased$2,681 million , as increased commodity pricing and natural gas and liquids production were only partially offset by increased operating costs and expenses. •Net cash provided by operating activities of$1,363 million increased 158% from$528 million in 2020, primarily due to a$2,768 million increase resulting from higher commodity prices, a$524 million increase related to increased production and a$56 million increase in our marketing margin. The increases were partially offset by a$1,854 million decrease in settled derivatives, a$477 million increase in operating costs and expenses, a$132 million decreased impact of working capital and a$42 million increase in interest expense.
•Net cash provided by operating activities, net of changes in working capital,
was
•Total capital invested of$1,108 million increased 23% from$899 million in 2020, as we applied our capital discipline to our recently-acquired natural gas and oil properties, investing at levels designed to keep daily production consistent with the end of the prior year.
E&P
•E&P segment operating income was$2,583 million in 2021, compared to an operating loss of$2,864 million in 2020. E&P segment operating loss in 2020 included$2,825 million in non-cash full cost ceiling impairments. Excluding the non-cash 55
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impairments, E&P segment operating income increased
•Year-end reserves of 21,148 Bcfe increased 9,158 Bcfe, or 76%, from 11,990 Bcfe at the end of 2020, as 5,753 Bcfe of acquired reserves, 3,962 Bcfe of additions and 684 Bcfe of positive price and performance revisions were only partially offset by 1,240 Bcfe of production and 1 Bcfe associated with properties that were sold. •Total net production of 1,240 Bcfe, which was comprised of 82% natural gas, 15% NGLs and 3% oil, increased 41% from 880 Bcfe in 2020. Approximately 80% of this increase came from properties acquired from Montage and Indigo. •Excluding the effect of derivatives, our realized natural gas price of$3.31 per Mcf, realized oil price of$58.80 per barrel and realized NGL price of$28.72 per barrel increased 147%, 101% and 180%, respectively, from 2020. Our weighted average realized price excluding the effect of derivatives of$3.74 per Mcfe increased 144% from the same period in 2020.
•The E&P segment invested
Outlook
Our primary focus in 2022 is to maintain our production profile and improve the safety and efficiency of our operations to optimize our ability to generate free cash flow and further strengthen our balance sheet.
As we develop our core positions in the Appalachian and
•Creating Value. We seek to create value for our stakeholders by allocating capital that is focused on earning economic returns; delivering free cash flow; upgrading the quality, depth and capital efficiency of our drilling inventory; and converting resources to proved reserves. •Financial Strength. We intend to protect our financial strength by lowering our leverage ratio and total debt; extending the weighted average years to maturity of our debt; lowering our cost of debt; deploying hedges to protect against downward price movement; covering our costs and meeting other financial commitments; and maintaining a strong liquidity position. •Focus on Execution. We are focused on operating effectively and efficiently with HSE and ESG as core values; building on our data analytics, operating execution, strategic sourcing, vertical integration and large-scale asset development expertise; further enhancing well performance, optimizing well costs and reducing base production declines; growing margins and securing flow assurance through commercial and marketing arrangements. •Capturing the Tangible Benefits of Scale. We strive to create a competitive advantage through strategic transactions that we believe will enhance enterprise returns and deliver financial synergies and operational economies. We believe these transactions lower the risk of our business, expand our opportunity set, increase business optionality and build upon our demonstrated record of asset integration. We remain committed to achieving these objectives while maintaining our commitment to being environmentally conscious. We believe that we and our industry will continue to face challenges due to evolving environmental standards by both regulators and investors, the uncertainty of natural gas, oil and NGL prices inthe United States , changes in laws, regulations and investor sentiment, and other key factors described above under " Risk Factors. " As such, we intend to protect our financial strength by reducing our debt while continuing to extend the weighted average years to maturity of our debt, and by maintaining a derivative program designed to reduce our exposure to commodity price volatility. COVID-19 During 2021, we did not experience any material impact to our ability to operate or market our production due to the direct or indirect impacts of the COVID-19 pandemic, and we continue to monitor its impact on all aspects of our business. The COVID-19 outbreak resulted in state and local governments implementing measures with various levels of stringency to help control the spread of the virus. TheU.S. Department of Homeland Security classifies individuals engaged in and supporting exploration for and production of natural gas, oil and NGLs as "essential critical infrastructure workforce," and to date, state and local governments have followed this guidance and exempted these activities from business closures. Should this situation change, our access to supplies or workers to drill, complete and operate wells could be materially and adversely affected. Ensuring the health and welfare of our employees, and all who visit our sites, is our top priority, and we are following allU.S. Centers for Disease Control and Prevention and state and local health department guidelines. Further, we implemented infection control measures at all our sites and put in place travel and in-person meeting restrictions and other physical distancing measures. The degree to which the COVID-19 pandemic or any other public health crisis adversely impacts our operations will depend on future developments, which are uncertain and cannot be predicted, including, but not limited to, the duration and spread of the 56
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outbreak, its severity, the effectiveness of the vaccines and the actions to
contain the virus or treat its impact, its impact on the economy and market
conditions, and how quickly and to what extent normal economic and operating
conditions can resume. We will continually monitor our capital investment
program to take into account these changed conditions and proactively adjust our
activities and plans. Therefore, while this continued matter could potentially
disrupt our operations, the degree of the potentially adverse financial impact
cannot be reasonably estimated at this time.
RESULTS OF OPERATIONS
The following discussion of our results of operations for our segments is
presented before intersegment eliminations. We evaluate our segments as if they
were stand-alone operations and accordingly discuss their results prior to any
intersegment eliminations. Interest expense, gain (loss) on derivatives, gain
(loss) on early extinguishment of debt and income taxes are discussed on a
consolidated basis.
We have applied the Securities and Exchange Commission's recently adopted FAST
Act Modernization and Simplification of Regulation S-K, which limits the
discussion to the two most recent fiscal years. This discussion and analysis
deals with comparisons of material changes in the consolidated financial
statements for fiscal year 2021 and fiscal year 2020. For the comparison of
fiscal year 2020 and fiscal year 2019, see "Management's Discussion and Analysis
of Financial Condition and Results of Operations" in Part II, Item 7 of our 2020
Annual Report on Form 10-K, filed with the Securities and Exchange Commission on
March 1, 2021 .
E&P
For the years ended December 31,
(in millions) 2021 2020
Revenues $ 4,640 (1) $ 1,348 (1)
Operating costs and expenses 2,057 (2) 4,212 (3)
Operating income (loss) $ 2,583 $ (2,864)
Gain (loss) on derivatives, settled $ (1,492)
(1)Includes
(2)Includes$76 million in Merger-related expenses,$7 million of restructuring charges and$6 million of non-cash, non-full cost pool impairments for the year endedDecember 31, 2021 . (3)Includes$2,825 million of non-cash full cost ceiling test impairments,$41 million in Merger-related expenses,$16 million of restructuring charges and$5 million of non-cash, non-full cost pool asset impairments for the year endedDecember 31, 2020 .
(4)Includes
Operating Income
•E&P segment operating income for the year endedDecember 31, 2021 was$2,583 million compared to an operating loss of$2,864 million for the year endedDecember 31, 2020 . The E&P segment operating loss in 2020 included$2,825 million of non-cash full cost ceiling test impairments. Excluding the non-cash full cost ceiling test impairments in 2020, E&P segment operating income increased$2,622 million for the year endedDecember 31, 2021 , as a 144% improvement in weighted average commodity pricing, excluding derivatives, and a 41% increase in production volumes more than offset a 48% increase in E&P operating costs.
Revenues
The following illustrate the effects on sales revenues associated with changes in commodity prices and production volumes:
For the years ended
Natural
(in millions except percentages) Gas Oil NGLs Total
2020 sales revenues (1) $ 928 $ 150 $ 265 $ 1,343
Changes associated with prices 2,000 196 572 2,768
Changes associated with production volumes 430 43 51 524
2021 sales revenues (1) $ 3,358 $ 389 $ 888 $ 4,635
Increase from 2020 262 % 159 % 235 % 245 %
(1)Excludes
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Production Volumes
For the years ended December 31,
2021 2020 Increase/(Decrease)Natural Gas (Bcf) Appalachia 883 694 27% Haynesville (1) 132 - 100% Other - - -% Total 1,015 694 46% Oil (MBbls) Appalachia 6,567 5,124 28% Haynesville (1) 8 - 100% Other 35 17 106% Total 6,610 5,141 29% NGL (MBbls) Appalachia 30,936 25,923 19% Other 4 4 -% Total 30,940 25,927 19% Production volumes by area (Bcfe): Appalachia 1,108 880 26% Haynesville (1) 132 - 100% Other - - -% Total 1,240 880 41% Total Production by Formation (Bcfe) Marcellus Shale 943 858 10% Utica Shale (2) 164 22 645% Haynesville Shale (1) 100 - 100% Bossier Shale (1) 32 - 100% Other 1 - 100% Total 1,240 880 41% Production percentage: Natural gas 82 % 79 % Oil 3 % 4 % NGL 15 % 17 %
(1)The Haynesville E&P assets were acquired through the Indigo Merger in
(2)The increase in production from the
•Production volumes for our E&P segment increased 360 Bcfe for the year endedDecember 31, 2021 , compared to the same period in 2020, primarily due the recent acquisitions of producing natural gas and oil properties in Appalachia from Montage inNovember 2020 and theHaynesville from Indigo inSeptember 2021 . Production from these properties accounted for 80% of the increase in production volumes in 2021, as compared to 2020. •Oil and NGL production increased 29% and 19%, respectively, for the year endedDecember 31, 2021 , compared to 2020, primarily due to our increased activities in Appalachia, as we moved to take advantage of favorable liquids pricing.
Commodity Prices
The price we expect to receive for our production is a critical factor in
determining the capital investments we make to develop our properties. Commodity
prices fluctuate due to a variety of factors we can neither control nor predict,
including increased supplies of natural gas, oil or NGLs due to greater
exploration and development activities, weather conditions, political and
economic events such as the response to the COVID-19 pandemic, and competition
from other energy sources. These factors
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impact supply and demand, which in turn determine the sales prices for our
production. In addition to these factors, the prices we realize for our
production are affected by our derivative activities as well as locational
differences in market prices, including basis differentials. We will continue to
evaluate the commodity price environments and adjust the pace of our activity in
order to maintain appropriate liquidity and financial flexibility.
For the years ended December 31,
Increase/
2021 2020 (Decrease)
Natural Gas Price:
NYMEX Henry Hub Price ($/MMBtu) (1) $ 3.84 $ 2.08 85%
Discount to NYMEX (2) (0.53) (0.74) (28)%
Average realized gas price, excluding derivatives ($/Mcf) $ 3.31 $ 1.34 147%
Gain on settled financial basis derivatives ($/Mcf) 0.09 0.11
Gain (loss) on settled commodity derivatives ($/Mcf) (1.12) 0.25
Average realized gas price, including derivatives ($/Mcf) $ 2.28 $ 1.70 34%
Oil Price:
WTI oil price ($/Bbl) (3) $ 67.92 $ 39.40 72%
Discount to WTI (4) (9.12) (10.20) (11)%
Average oil price, excluding derivatives ($/Bbl) $ 58.80 $ 29.20 101%
Gain (loss) on settled derivatives ($/Bbl) (18.32) 17.71
Average oil price, including derivatives ($/Bbl) $ 40.48 $ 46.91 (14)%
NGL Price:
Average realized NGL price, excluding derivatives ($/Bbl) $ 28.72 $ 10.24 180%
Gain (loss) on settled derivatives ($/Bbl) (10.52) 0.91
Average realized NGL price, including derivatives ($/Bbl) $ 18.20 $ 11.15 63%
Percentage of WTI, excluding derivatives 42 % 26 %
Total Weighted Average Realized Price:
Excluding derivatives ($/Mcfe) $ 3.74 $ 1.53 144%
Including derivatives ($/Mcfe) $ 2.53 $ 1.94 30%
(1)Based on last day settlement prices from monthly futures contracts.
(2)This discount includes a basis differential, a heating content adjustment, physical basis sales, third-party transportation charges and fuel charges, and excludes financial basis hedges.
(3)Based on the average daily settlement price of the nearby month futures contract over the period.
(4)This discount primarily includes location and quality adjustments.
We receive a sales price for our natural gas at a discount to average monthly NYMEX settlement prices based on heating content of the gas, locational basis differentials and transportation and fuel charges. Additionally, we receive a sales price for our oil and NGLs at a difference to average monthlyWest Texas Intermediate settlement and Mont Belvieu NGL composite prices, respectively, due to a number of factors including product quality, composition and types of NGLs sold, locational basis differentials and transportation and fuel charges. We regularly enter into various derivatives and other financial arrangements with respect to a portion of our projected natural gas, oil and NGL production in order to ensure certain desired levels of cash flow and to minimize the impact of price fluctuations, including fluctuations in locational market differentials. We refer you to Item 7A, Quantitative and Qualitative Disclosures about Market Risk , of this Annual Report, Note 6 to the consolidated financial statements included in this Annual Report, and the risk factor "Our commodity price risk management and measurement systems and economic hedging activities might not be effective and could increase the volatility of our results" included in Item 1A in this Annual Report for additional discussion about our derivatives and risk management activities. 59
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The tables below present the amount of our future natural gas production in
which the impact of basis volatility has been limited through derivatives and
physical sales arrangements as of
Volume (Bcf) Basis Differential
Basis Swaps - Natural Gas
2022 322 $ (0.38)
2023 200 (0.45)
2024 46 (0.71)
2025 9 (0.64)
Total 577
Physical NYMEX Sales Arrangements - Natural Gas (1)
2022 645 $ (0.11)
2023 521 (0.08)
2024 389 (0.06)
2025 308 (0.04)
2026 134 0.00
2027 125 0.01
2028 125 0.01
2029 125 0.01
2030 47 0.00
Total 2,419
(1)Physical sales volumes are presented on a gross basis.
In addition to protecting basis, the table below presents the amount of our future production in which price is financially protected through derivatives as ofDecember 31, 2021 : 2022 2023 2024 Natural gas (Bcf) 1,297 923 279 Oil (MBbls) 4,583 2,114 54 Ethane (MBbls) 5,932 432 - Propane (MBbls) 6,674 518 - Normal butane (MBbls) 1,587 164 - Natural gasoline (MBbls) 1,840 157 -
Total financial protection on future production (Bcfe) 1,421 943
279
We refer you to Note 6 of the consolidated financial statements included in this Annual Report for additional details about our derivative instruments.
Operating Costs and Expenses
For the years ended December 31,
(in millions except percentages) 2021 2020 Increase/(Decrease)
Lease operating expenses $ 1,175 $ 815 44%
General & administrative expenses 124 108 15%
Merger-related expenses 76 41 85%
Restructuring charges 7 16 (56)%
Taxes, other than income taxes 132 54 144%
Full cost pool amortization 521 333 56%
Non-full cost pool DD&A 16 15 7%
Impairments 6 2,830 (100)%
Total operating costs $ 2,057 $ 4,212 (51)%
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For the years ended December 31,
Average unit costs per Mcfe: 2021 2020 Increase/(Decrease)
Lease operating expenses (1) $ 0.95 $ 0.93 2%
General & administrative expenses $ 0.10 (2) $ 0.12 (3) (17)%
Taxes, other than income taxes $ 0.11 $ 0.06 83%
Full cost pool amortization $ 0.42 $ 0.38 11%
(1)Includes post-production costs such as gathering, processing, fractionation and compression.
(2)Excludes
(3)Excludes$41 million in merger-related expenses,$16 million in restructuring charges and$1 million of legal settlement charges for the year endedDecember 31, 2020 . Lease Operating Expenses
•Lease operating expenses per Mcfe increased
General and Administrative Expenses
•General and administrative expenses increased$16 million for the year endedDecember 31, 2021 , compared to 2020, primarily due to increased personnel costs associated with our expanded operations in Appalachia and theHaynesville . •On a per Mcfe basis, excluding merger-related expenses, restructuring charges and legal settlement charges, general and administrative expenses per Mcfe decreased by$0.02 for the year endedDecember 31, 2021 , compared to 2020, as a 41% increase in production volumes more than offset a 16% increase in expenses.
Merger-Related Expenses
•Beginning with the Montage Merger inNovember 2020 , we have focused on building scale and geographic diversification throughout 2021. As a result of this strategy, we merged with Indigo inSeptember 2021 and GEPH onDecember 31, 2021 . The table below presents the charges incurred for our merger-related activities for the years endedDecember 31, 2021 and 2020:
For the years ended
2021 2020
Indigo GEPH Montage Montage
(in millions) Merger Merger Merger Total Merger
Professional fees (bank, legal, consulting)
$ 1 $ 47 $ 18 Representation & warranty insurance 4 7 - 11 - Contract buyouts, terminations and transfers 7 1 - 8 5 Due diligence and environmental 3 1 - 4 - Employee-related 2 - 1 3 17 Other 2 - 1 3 1 Total merger-related expenses$ 45 $ 28 $ 3 $ 76 $ 41
We refer you to Note 2 of the consolidated financial statements included in this Annual Report for additional details about the Mergers.
Restructuring Charges
•InFebruary 2021 , employees were notified of a workforce reduction plan as part of an ongoing strategic effort to reposition our portfolio, optimize operational performance and improve margins. Affected employees were offered a severance package, which included a one-time payment depending on length of service and, if applicable, the current value of unvested long-term incentive awards that were forfeited. These costs were recognized as restructuring charges for the year endedDecember 31, 2021 , and were substantially complete by the end of the first quarter of 2021. For the year endedDecember 31, 2021 , we recognized a total restructuring expense of$7 million primarily related to cash severance, including payroll taxes.
•In
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depending on length of service and, if applicable, the current value of unvested long-term incentive awards that were forfeited. We also recognized additional severance costs in the fourth quarter of 2020 related to continued organizational restructuring. For the year endedDecember 31, 2020 , we recognized a total restructuring expense of$16 million primarily related to cash severance, including payroll taxes.
See Note 3 of the consolidated financial statements included in this Annual Report for additional details about our restructuring charges.
Taxes, Other than Income Taxes
•Taxes other than income taxes per Mcfe may vary from period to period due to changes in ad valorem and severance taxes that result from the mix of our production volumes and fluctuations in commodity prices. Taxes, other than income taxes, per Mcfe increased$0.05 per Mcfe for the year endedDecember 31, 2021 , compared to the same period in 2020, primarily due to the impact of higher commodity pricing on our severance taxes inWest Virginia , which are calculated as a fixed percentage of revenue net of allowable production expenses, and the impact of incremental severance and ad valorem taxes associated with our acquired assets inLouisiana .
Full Cost Pool Amortization
•Our full cost pool amortization rate increased$0.04 per Mcfe for the year endedDecember 31, 2021 , as compared to 2020. The average amortization rate increased primarily as a result of the impact of our acquisitions of natural gas and oil properties in Appalachia and theHaynesville . •The amortization rate is impacted by the timing and amount of reserve additions and the future development costs associated with those additions, revisions of previous reserve estimates due to both price and well performance, write-downs that result from non-cash full cost ceiling impairments, proceeds from the sale of properties that reduce the full cost pool, and the levels of costs subject to amortization. We cannot predict our future full cost pool amortization rate with accuracy due to the variability of each of the factors discussed above, as well as other factors, including but not limited to the uncertainty of the amount of future reserve changes.
•Unevaluated costs excluded from amortization were
•No impairment expense was recorded in 2020 or 2021 in relation to our natural gas and oil properties acquired from Montage. These properties were recorded at fair value as ofNovember 13, 2020 , in accordance with ASC Topic 820 - Fair Value Measurement. In the fourth quarter of 2020, pursuant toSEC guidance, we determined that the fair value of the properties acquired at the closing of the Montage Merger clearly exceeded the related full-cost ceiling limitation beyond a reasonable doubt and received a waiver from theSEC to exclude the properties acquired in the Montage Merger from the ceiling test calculation. This waiver was granted for all reporting periods through and including the quarter endingSeptember 30, 2021 , as long as we could continue to demonstrate that the fair value of properties acquired clearly exceeded the full cost ceiling limitation beyond a reasonable doubt in each reporting period. As part of the waiver received from theSEC , we were required to disclose what the full cost ceiling test impairment amounts for all periods presented in each applicable quarterly and annual filing would have been if the waiver had not been granted. The fair value of the properties acquired in the Montage Merger was based on future commodity market pricing for natural gas and oil pricing existing at the date of the Montage Merger, and we affirmed that there has not been a material decline to the fair value of these acquired assets since the Montage Merger. The properties acquired in the Montage Merger had an unamortized cost atDecember 31, 2020 of$1,087 million . Had we not received the waiver from theSEC , the impairment charge recorded would have been an additional$539 million for the year endedDecember 31, 2020 . Due to the improvement in commodity prices during 2021, no impairment charge would have been recorded in 2021 had the Montage natural gas and oil properties been included in the full cost ceiling test.
See " Supplemental Oil and Gas Disclosures " in Item 8 of Part II of this Annual Report for additional information regarding our unevaluated costs excluded from amortization.
Impairments
•We recognized a
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•For the year endedDecember 31, 2020 , we recognized$2,825 million in non-cash full cost ceiling test impairments, primarily due to decreased commodity pricing over the prior 12 months. Additionally, we recognized a$5 million impairment to non-core E&P assets. Marketing For the years ended December 31, (in millions except percentages) 2021 2020 Increase/(Decrease) Marketing revenues$ 6,186 $ 2,145 188% Other operating revenues 3 - 100% Marketing purchases 6,114 2,129 187% Operating costs and expenses 23 23 -% Operating income (loss)$ 52 $ (7) 843% Volumes marketed (Bcfe) 1,542 1,138 36%
Percent natural gas production marketed from affiliated E&P operations
95 % 89 %
Affiliated E&P oil and NGL production marketed 82 % 81 %
Operating Income (Loss)
•Marketing operating income increased $59 million for the year ended
December 31, 2021 , compared to 2020, primarily due to a $56 million increase in
the marketing margin as well as a $1 million increase in gas storage gains and
$2 million in non-performance damages received, both recorded in other operating
revenues. Operating costs and expenses remained flat over the periods presented.
•The margin generated from marketing activities increased $56 million for the
year ended December 31, 2021 , as compared to the prior year, primarily due to a
36% increase in volumes marketed and a corresponding reduction in third-party
purchases and sales, which were used in 2020 to optimize our transportation
folio, due to increased affiliated volumes available for marketing.
Marketing margins are driven primarily by volumes marketed and may fluctuate
depending on the prices paid for commodities, related cost of transportation and
the ultimate disposition of those commodities. Increases and decreases in
revenues due to changes in commodity prices and volumes marketed are largely
offset by corresponding changes in purchase expenses. Efforts to optimize the
cost of our transportation can result in greater expenses and therefore lower
marketing margins.
Revenues
•Revenues from our marketing activities increased $4,041 million for the year
ended December 31, 2021 , compared to 2020, primarily due to a 113% increase in
the price received for volumes marketed and a 404 Bcfe increase in the volumes
marketed.
Operating Costs and Expenses
•Marketing operating costs and expenses remained flat for the year ended
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Consolidated
Interest Expense
For the years ended
Increase/
(in millions except percentages) 2021 2020 (Decrease)
Gross interest expense:
Senior notes $ 190 $ 155 23%
Credit arrangements 30 16 88%
Amortization of debt costs 13 11 18%
Total gross interest expense 233 182 28%
Less: capitalization (97) (88) 10%
Net interest expense $ 136 $ 94 45%
•Interest expense related to our senior notes increased for the year ended
December 31, 2021 , as compared to 2020, as the interest savings from the
repurchase of $1,091 million of our outstanding senior notes in 2021 was offset
by the interest associated with the August 2021 public offering of $1,200
million aggregate principal amount of our 5.375% Senior Notes due 2030 and the
September 2021 assumption of Indigo Notes, which were exchanged for $700 million
aggregate principal amount of our 5.375% Senior Notes due 2029 related to the
Indigo Merger. In late December 2021 , we issued $1,150 million aggregate
principal amount of our 4.75% Senior Notes due 2032 and $550 million of Term
Loan financing, subject to a variable interest rate of 3% at December 31, 2021 ,
each of which will have the effect of increasing our gross interest expense in
2022.
•We capitalize interest associated with the cost of acquiring and assessing our
unevaluated natural gas and oil properties. Capitalized interest increased $9
million for the year ended December 31, 2021 , compared to 2020, as the
acquisition of unevaluated Haynesville natural gas and oil properties on
September 1, 2021 outpaced the evaluation of our existing unevaluated natural
gas and oil properties over the past twelve months. The impact of the addition
of unevaluated Haynesville properties from the Indigo Merger and the GEPH Merger
is expected to increase the amount of capitalized interest until such time as
they are evaluated.
•Capitalized interest decreased as a percentage of gross interest expense for
the year ended December 31, 2021 , as compared to 2020, primarily as a result of
the smaller percentage change in the unevaluated natural gas and oil properties
for most of 2021, prior to the acquisitions of the Haynesville unevaluated
natural gas and oil properties, as compared to the larger increase in gross
interest expense during 2021, associated with increased debt levels as a result
of the Montage Merger and the Indigo Merger over the same period.
We refer you to Note 9 to the consolidated financial statements included
in this Annual Report for additional details about our debt and our financing
activities.
Gain (Loss) on Derivatives
For the years ended December 31,
(in millions) 2021 2020
Loss on unsettled derivatives $ (945) $ (139)
Gain (loss) on settled derivatives (1,492) 362
Non-performance risk adjustment 1
1
Total gain (loss) on derivatives $ (2,436)$ 224
We refer you to Note 6 to the consolidated financial statements included in this Annual Report for additional details about our gain (loss) on derivatives.
Gain (Loss) on Early Extinguishment of Debt
•For the year endedDecember 31, 2021 , we recorded a loss on early extinguishment of debt of$93 million as a result of our repurchase of$1,091 million in aggregate principal amount of our outstanding senior notes for$1,177 million in cash, including premiums and fees, and the write-off of$7 million in related unamortized debt discounts and issuance costs. •In 2020, we recorded a gain on early extinguishment of debt of$35 million as a result of our repurchase of$107 million in aggregate principal amount of our outstanding senior notes for$72 million . See Note 9 to the consolidated financial statements of this Annual Report for more information on our long-term debt. 64
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Income Taxes
For the years ended December 31,
(in millions except percentages) 2021 2020 Income tax expense (benefit) $ -$ 407 Effective tax rate 0 % (15) % •In 2020, due to significant pricing declines and the material write-down of the carrying value of our natural gas and oil properties in addition to other negative evidence, management concluded that it was more likely than not that a portion of our deferred tax assets would not be realized and recorded a valuation allowance. As ofDecember 31, 2021 , we still maintain a full valuation allowance. We also retained a valuation allowance of$59 million related to net operating losses in jurisdictions in which we no longer operate. Management will continue to assess available positive and negative evidence to estimate whether sufficient future taxable income will be generated to permit the use of deferred tax assets. The amount of the deferred tax asset considered realizable, however, could be adjusted based on changes in subjective estimates of future taxable income or if objective negative evidence is no longer present. •Due to the issuance of common stock associated with the Indigo Merger, as discussed in Note 2 to the consolidated financial statements to this Annual Report, we incurred a cumulative ownership change and as such, our net operating losses ("NOLs") prior to the acquisition are subject to an annual limitation under Internal Revenue Code Section 382 of approximately$48 million . The ownership changes and resulting annual limitation will result in the expiration of NOLs or other tax attributes otherwise available, with a corresponding decrease in our valuation allowance. AtDecember 31, 2021 , we had approximately$4 billion of federal NOL carryovers, of which approximately$3 billion have an expiration date between 2035 and 2037 and$1 billion have an indefinite carryforward life. We currently estimate that approximately$2 billion of these federal NOLs will expire before they are able to be used. The non-expiring NOLs remain subject to a full valuation allowance. If a subsequent ownership change were to occur as a result of future transactions in our common stock, our use of remainingU.S. tax attributes may be further limited.
We refer you to Note 11 to the consolidated financial statements included in this Annual Report for additional discussion about our income taxes.
LIQUIDITY AND CAPITAL RESOURCES
We depend primarily on funds generated from our operations, our 2018 credit
facility, our cash and cash equivalents balance and capital markets as our
primary sources of liquidity. In October 2021 , the banks participating in our
2018 credit facility reaffirmed our elected borrowing base and aggregate
commitments to be $2.0 billion . At December 31, 2021 , we had approximately $1.4
billion of total available liquidity, which exceeds our currently modeled needs
as we remain committed to our strategy of capital discipline.
In November 2021 in conjunction with the GEPH Merger, we amended our 2018 credit
facility agreement to permit access to additional secured debt capacity in the
form of a term loan for incremental capital up to $900 million , ranking equally
with our 2018 credit facility. In December 2021 , we raised $550 million in term
loan financing to partially fund the GEPH Merger, with no impact to our
liquidity at year end. The remaining $350 million of incremental term loan
capacity remains accessible through November 2022 and provides access to another
secured debt capital source for liquidity purposes.
Our flexibility to access incremental secured debt capital is derived from our
excess asset collateral value above the elected $2.0 billion borrowing base and
aggregate commitments of our 2018 credit facility. Our ability to issue secured
debt is governed by the limitations of our 2018 credit facility as well as our
secured debt capacity (as defined by our senior note indentures) which was $3.7
billion as of December 31, 2021 , based on 25% of adjusted consolidated net
tangible assets.
Looking forward in 2022, we expect to continue to generate free cash flow from
operations, net of changes in working capital, in excess of our expected capital
investments, and we intend to utilize this free cash flow to pay down our debt.
We refer you to Note 9 to the consolidated financial statements included in
this Annual Report and the section below under "Credit Arrangements and
Financing Activities" for additional discussion of our 2018 credit facility and
related covenant requirements.
Our cash flow from operating activities is highly dependent upon our ability to
sell and the sales prices that we receive for our natural gas and liquids
production. Natural gas, oil and NGL prices are subject to wide fluctuations and
are driven by market supply and demand, which is impacted by many factors. See
"Market Conditions and Commodity Prices" in the Overview section of Item 7
in Part II for additional discussion about current and potential future market
conditions. The sales price we receive for our production is also influenced by
our commodity derivative program. Our derivative contracts allow us to ensure a
certain level of cash flow to fund our operations. Although we are continually
adding additional derivative positions for portions of our expected 2022, 2023
and 2024 production, there can be no assurance that we will be able to add
derivative positions to cover the
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remainder of our expected production at favorable prices. See "Risk Factors" in Item 1A, " Quantitative and Qualitative Disclosures about Market Risk " in Item 7A and Note 6 in the consolidated financial statements included in this Annual Report for further details. Our commodity hedging activities are subject to the credit risk of our counterparties being financially unable to settle the transaction. We actively monitor the credit status of our counterparties, performing both quantitative and qualitative assessments based on their credit ratings and credit default swap rates where applicable, and to date have not had any credit defaults associated with our transactions. However, any future failures by one or more counterparties could negatively impact our cash flow from operating activities. Our short-term cash flows are also dependent on the timely collection of receivables from our customers and joint interest owners. We actively manage this risk through credit management activities and, through the date of this filing, have not experienced any significant write-offs for non-collectable amounts. However, any sustained inaccessibility of credit by our customers and joint interest owners could adversely impact our cash flows. Due to these factors, we are unable to forecast with certainty our future level of cash flow from operations. Accordingly, we expect to adjust our discretionary uses of cash depending upon available cash flow. Further, we may from time to time seek to retire, rearrange or amend some or all of our outstanding debt or debt agreements through cash purchases, and/or exchanges, open market purchases, privately negotiated transactions, tender offers or otherwise. Such transactions, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.
Credit Arrangements and Financing Activities
InApril 2018 , we entered into a revolving credit facility (the "2018 credit facility") with a group of banks that, as amended, has a maturity date ofApril 2024 . The 2018 credit facility has an aggregate maximum revolving credit amount of$3.5 billion and, inOctober 2021 , the banks participating in our 2018 credit facility reaffirmed the elected borrowing base to be$2.0 billion , which also reflected our aggregate commitments. The borrowing base is subject to redetermination at least twice a year, which typically occurs in April and October, and is subject to change based primarily on drilling results, commodity prices, our future derivative position, the level of capital investment and operating costs. The 2018 credit facility is secured by substantially all of our assets, including most of our subsidiaries. The permitted lien provisions in certain senior note indentures currently limit liens securing indebtedness to the greater of$2.0 billion or 25% of adjusted consolidated net tangible assets. We may utilize the 2018 credit facility in the form of loans and letters of credit. As ofDecember 31, 2021 , we had$460 million of borrowings on our 2018 credit facility and$160 million in outstanding letters of credit. We currently do not anticipate being required to supply a materially greater amount of letters of credit under our existing contracts. We refer you to Note 9 to the consolidated financial statements included in this Annual Report for additional discussion of our 2018 credit facility.
As of
Our ability to comply with financial covenants in future periods depends, among other things, on the success of our development program and upon other factors beyond our control, such as the market demand and prices for natural gas and liquids. We refer you to Note 9 of the consolidated financial statements included in this Annual Report for additional discussion of the covenant requirements of our 2018 credit facility. The credit status of the financial institutions participating in our 2018 credit facility could adversely impact our ability to borrow funds under the 2018 credit facility. Although we believe all of the lenders under the facility have the ability to provide funds, we cannot predict whether each will be able to meet their obligation to us. We refer you to Note 9 to the consolidated financial statements included in this Annual Report for additional discussion of our 2018 credit facility. Our exposure to the anticipated transition from LIBOR is limited to the 2018 credit facility. The USD-LIBOR settings are expected to be published throughJune 2023 , and we anticipate using a variation of this rate until the underlying agreements are extended beyond the LIBOR publication date.
Key financing activities for the years ended
Debt and Common Stock Issuance
•OnDecember 22, 2021 , we completed a public offering of$1,150 million aggregate principal amount of our 4.75% Senior Notes due 2032 (the "2032 Notes"), with net proceeds from the offering totaling$1,133 million after underwriting discounts and offering expenses. The net proceeds were used to fund a portion of the GEPH Merger, which closed onDecember 31, 2021 , and to fund tender offers for$300 million of our 2025 Notes. The remaining proceeds were used for general corporate purposes. 66
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•In contemplation of the GEPH Merger, onDecember 22, 2021 , we entered into a term loan credit agreement with a group of lenders that provided for a$550 million secured term loan facility which matures onJune 22, 2027 (the "Term Loan"). As ofDecember 31, 2021 , we had borrowings under the Term Loan of$550 million . The net proceeds from the initial loans of$542 million were used to fund a portion of the GEPH Merger onDecember 31, 2021 . •OnDecember 31, 2021 , we issued 99,337,748 shares of our common stock in conjunction with the GEPH Merger. These shares of our common stock had an aggregate dollar value equal to approximately$463 million , based on the closing price of$4.66 per share of our common stock on the NYSE onDecember 31, 2021 . See Note 2 for additional details on the GEPH Merger. •InNovember 2021 , in contemplation of the GEPH Merger, we amended our 2018 credit facility agreement to permit access to additional secured debt capacity in the form of the previously-described Term Loan for incremental capital up to$900 million , ranking equally with our 2018 credit facility. As ofDecember 31, 2021 , we had borrowings under the Term Loan of$550 million , which were used to partially fund the GEPH Merger, and$350 million of incremental term loan capacity, which remains accessible throughNovember 2022 . •InAugust 2021 , we completed a public offering of$1,200 million aggregate principal amount of our 5.375% Senior Notes due 2030 (the "2030 Notes"), with net proceeds from the offering totaling$1,183 million after underwriting discounts and offering expenses. The proceeds were used to repurchase the$791 million principal amount of certain of our outstanding senior notes. The remaining proceeds were used to pay borrowings under our 2018 credit facility and for general corporate purposes, including consideration for the Indigo Merger.
•In
•In conjunction with the Indigo Merger and pursuant to the terms of the merger agreement, inSeptember 2021 , we assumed$700 million in aggregate principal amount of Indigo's 5.375% Senior Notes due 2029 (the "Indigo Notes"). Subsequent to the Indigo Merger, we exchanged the Indigo Notes for approximately$700 million of newly issued 5.375% Senior Notes due 2029. •InNovember 2020 , we issued 69,740,848 shares of our common stock in conjunction with the Montage Merger. These shares of our common stock had an aggregate dollar value equal to approximately$213 million , based on the closing price of$3.05 per share of our common stock on the NYSE onNovember 13, 2020 . See Note 2 for additional details on the Montage Merger. •InAugust 2020 , we completed a public offering of$350 million aggregate principal amount of our 2028 Notes, with net proceeds from the offering totaling approximately$345 million after underwriting discounts and offering expenses. The net proceeds were used to fund a portion of the Montage Merger inNovember 2020 . •InAugust 2020 , we completed a public offering of 63,250,000 shares of our common stock with an offering price to the public of$2.50 per share. Net proceeds, after deducting underwriting discounts and offering expenses, were approximately$152 million . The proceeds from the common stock offering, in conjunction with the issuance of the 2028 Notes and additional borrowings on our 2018 credit facility were used to fund a redemption of$510 million aggregate principal amount of Montage's senior notes in connection with the closing of the Montage Merger. Debt Repurchases •In 2021, we repurchased$6 million of our 4.10 % Senior Notes due 2022,$467 million of our 4.95% Senior Notes due 2025 and$618 million of our 7.50% Senior Notes due 2026 for$1,177 million in cash, including premiums and fees, and we recognized an additional$7 million in unamortized debt expenses, resulting in a loss on early extinguishment of debt of$93 million . •In 2020, we repurchased$6 million of our 4.10% Senior Notes due 2022,$36 million of our 4.95% Senior Notes due 2025,$21 million of our 7.50% Senior Notes due 2026 and$44 million of our 7.75% Senior Notes due 2027 for$72 million , and recognized a$35 million gain on the extinguishment of debt. We refer you to Note 9 to the consolidated financial statements included in this Annual Report for additional discussion of our senior notes. 67
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InJanuary 2022 , we repurchased the remaining outstanding principal balance of$201 million on our 2022 Senior Notes using our 2018 credit facility. As a result of the focused work on refinancing and repayment of our debt in recent years, our outstanding revolver balance and$16 million of our Term Loan principal are the only debt balances scheduled to become due prior to 2025. AtFebruary 25, 2022 , we had long-term debt issuer ratings of Ba2 by Moody's (rating and stable outlook affirmed onNovember 29, 2021 ), BB+ by S&P (rating upgraded to BB+ with stable outlook onJanuary 6, 2022 ) and BB by Fitch Ratings (rating and stable outlook affirmed onNovember 29, 2021 ). Effective inJuly 2018 , the interest rate for our 2025 Notes was 6.20%, reflecting a net downgrade in our bond ratings since their issuance. InApril 2020 , S&P downgraded our bond rating to BB-, which had the effect of increasing the interest rate on the 2025 Notes to 6.45% inJuly 2020 , with the first coupon payment at the higher interest rate inJanuary 2021 . OnSeptember 1, 2021 , S&P upgraded our bond rating to BB, and onJanuary 6, 2022 , S&P further upgraded our bond rating to BB+, which will have the effect of decreasing the interest rate on the 2025 Notes to 5.95%, beginning with coupon payments afterJanuary 2022 . Any further upgrades or downgrades in our public debt ratings by Moody's or S&P could decrease or increase our cost of funds, respectively. Cash Flows For the years ended December 31, (in millions) 2021 2020 Net cash provided by operating activities$ 1,363 $ 528 Net cash used in investing activities (2,604) (881) Net cash provided by financing activities 1,256 361 Cash Flow from Operations For the years ended December 31, (in millions) 2021 2020 Net cash provided by operating activities$ 1,363 $ 528 Add back (subtract): changes in working capital 209 77
Net cash provided by operating activities, net of changes in working capital
$
1,572
•Net cash provided by operating activities increased 158% or$835 million for the year endedDecember 31, 2021 , compared to the same period in 2020, primarily due to a$2,768 million increase resulting from higher commodity prices, a$524 million increase related to increased production and a$56 million increase in our marketing margin. The increases were partially offset by a$1,854 million decrease in settled derivatives, a$477 million increase in operating costs and expenses, a$132 million decreased impact of working capital and a$42 million increase in interest expense.
•Net cash generated from operating activities, net of changes in working
capital, exceeded our capital investments by
Cash Flow from Investing Activities
•Total E&P capital investing increased$208 million for the year endedDecember 31, 2021 , compared to the same period in 2020, due to a$191 million increase in direct E&P capital investing, an$8 million increase in capitalized internal costs and a$9 million increase in capitalized interest. •Capitalized interest increased for the year endedDecember 31, 2021 , as compared to the same period in 2020, as the acquisition ofHaynesville unevaluated natural gas and oil properties onSeptember 1, 2021 outpaced the evaluation of our existing unevaluated natural gas and oil properties over the past twelve months. The impact of the addition of additionalHaynesville properties from the GEPH Merger onDecember 31, 2021 is expected to increase the amount of capitalized interest until such time as it is evaluated.
•Cash paid in mergers includes cash consideration of
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For the years ended December 31,
(in millions) 2021 2020
Additions to properties and equipment $ 1,032 $ 896
Adjustments for capital investments:
Changes in capital accruals 70 (3)
Other (1) 6 6
Total capital investing $ 1,108 $ 899 (1)Includes capitalized non-cash stock-based compensation and costs to retire assets, which are classified as cash used in operating activities.
Capital Investing
For
the years ended
Increase/
(in millions except percentages) 2021 2020 (Decrease)
E&P capital investing $ 1,107 $ 899
Other capital investing (1) 1 -
Total capital investing $ 1,108 $ 899 23%
(1)Other capital investing was immaterial for the year ended December 31, 2020 .
For the years ended December 31,
(in millions) 2021 2020
E&P Capital Investments by Type:
Exploratory and development, including workovers $ 886 $ 692
Acquisition of properties (2) 43 37
Water infrastructure project 5 9
Other 12 17
Capitalized interest and expenses 161 144
Total E&P capital investments $
1,107
E&P Capital Investments by Area Appalachia$ 882 $ 872 Haynesville 200 - Other E&P (1) 25 27Total E&P capital investments $
1,107
(1)Includes
(2)Excludes the impact of
For the years ended December 31,
2021 2020
Gross Operated Well Count Summary: Drilled 87 98 Completed 93 96 Wells to sales 93 100 Actual capital expenditure levels may vary significantly from period to period due to many factors, including drilling results, natural gas, oil and NGL prices, industry conditions, the prices and availability of goods and services, and the extent to which properties are acquired or non-strategic assets are sold.
Cash Flow from Financing Activities
•Net cash provided by financing activities for the year endedDecember 31, 2021 was$1,256 million , compared to net cash provided by financing activities of$361 million for the same period in 2020. •InDecember 2021 , we completed a public offering of$1,150 million aggregate principal amount of our 2032 Notes, with net proceeds from the offering totaling$1,133 million after underwriting discounts and offering expenses. The net proceeds were used to fund a portion of the GEPH Merger, which closed onDecember 31, 2021 , and to repurchase$300 million of our 2025 Notes. The remaining proceeds were used for general corporate purposes. 69
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•InDecember 2021 , we entered into our secured Term Loan facility and, as ofDecember 31, 2021 , had borrowings of$550 million outstanding. The net proceeds from the initial loans of$542 million were used to fund a portion of the GEPH Merger onDecember 31, 2021 .
•In
•In
•InAugust 2021 , we completed a public offering of$1,200 million aggregate principal amount of our 2030 Notes, with net proceeds from the offering totaling$1,183 million after underwriting discounts and offering expenses. The net proceeds were used to repurchase the$791 million principal amount of certain of our outstanding senior notes. The remaining proceeds were used to pay borrowings under our 2018 credit facility and for general corporate purposes, including consideration for the Indigo Merger. •InNovember 2020 , we paid$522 million to retire the Montage senior notes, and repaid the outstanding balance of$200 million related to Montage's revolving credit facility. •InAugust 2020 , we completed an underwritten public offering of 63,250,000 shares of our common stock with an offering price to the public of$2.50 per share. Net proceeds after deducting underwriting discounts and offering expenses were approximately$152 million .
•In 2020, we repurchased
We refer you to Note 9 to the consolidated financial statements included in this Annual Report for additional discussion of our outstanding debt and credit facility and to Note 1 for additional discussion of our equity offering. Working Capital •We had negative working capital of$1,639 million atDecember 31, 2021 , a$1,298 million decrease fromDecember 31, 2020 , as a$792 million increase in accounts receivable and a$15 million increase in cash were more than offset by$1,092 million reduction in the current mark-to-market value of our derivatives position related to improved forward pricing across all commodities, along with a$745 million increase in various payables and the reclassification of long-term debt to short-term debt of$206 million . Additionally, other current liabilities atDecember 31, 2021 increased$55 million , compared toDecember 31, 2020 , primarily due to the assumption of$47 million in liabilities related to the Indigo Merger and$8 million in prepayments/collateral received from certain customers. We believe that our existing cash and cash equivalents, our anticipated cash flow from operations and our available credit facility will be sufficient to meet our working capital and operational spending requirements.
Off-Balance Sheet Arrangements
We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As ofDecember 31, 2021 , our material off-balance sheet arrangements and transactions include operating service arrangements and$160 million in letters of credit outstanding against our 2018 credit facility. There are no other transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of our capital resources. For more information regarding off-balance sheet arrangements, we refer you to "Contractual Obligations and Contingent Liabilities and Commitments" below for more information on our operating leases. 70
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Contractual Obligations and Contingent Liabilities and Commitments
We have various contractual obligations in the normal course of our operations and financing activities. Significant contractual obligations as ofDecember 31, 2021 , were as follows: Contractual Obligations: Payments Due by Period Less than 1 More than 8 (in millions) Total Year 1 to 3 Years 3 to 5 Years 5 to 8 Years Years Transportation charges (1)$ 10,456 $ 1,144 $ 2,046 $ 1,894 $ 2,416 $ 2,956 Debt 5,440 206 471 400 2,013 2,350 Interest on debt (2) 2,037 262 543 484 552 196 Operating leases (3) 187 38 61 49 38 1 Compression services (4) 39 24 14 1 - - Operating agreements 89 54 18 12 5 - Purchase obligations 64 64 - - - - Other obligations (5) 10 7 3 - - -$ 18,322 $ 1,799 $ 3,156 $ 2,840 $ 5,024 $ 5,503 (1)As ofDecember 31, 2021 , we had commitments for demand and similar charges under firm transportation and gathering agreements to guarantee access capacity on natural gas and liquids pipelines and gathering systems. Of the total$10.5 billion ,$872 million related to access capacity on future pipeline and gathering infrastructure projects that still require the granting of regulatory approvals and/or additional construction efforts. For further information, we refer you to "Operational Commitments and Contingencies" in Note 10 to the consolidated financial statements included in this Annual Report. This amount also included guarantee obligations of up to$869 million . Prior to the Indigo Merger, inMay 2021 , Indigo closed on an agreement to divest itsCotton Valley natural gas and oil properties. Indigo retained certain contractual commitments related to volume commitments associated with natural gas gathering, for which Southwestern will assume the obligation to pay the gathering provider for any unused portion of the volume commitment under the agreement through 2027, depending on the buyer's actual use. As ofDecember 31, 2021 , up to approximately$36 million of these contractual commitments remain (included in the table above), and the Company has recorded a$17 million liability for its portion of the estimated future payments. Includes firm transportation commitments acquired with the Montage Merger totaling approximately$976 million . These commitments approximate$96 million within the next year,$192 million from 1 to 3 years,$189 million from 3 to 5 years,$270 million from 5 to 8 years and$229 million beyond 8 years. In the first quarter of 2019, we agreed to purchase firm transportation with pipelines in the Appalachian basin starting in 2021 and running through 2032, with$327 million in total contractual commitments remaining of which the seller has agreed to reimburse$100 million of these commitments.
(2)Interest payments on our senior notes were calculated utilizing the fixed
rates associated with our fixed rate notes outstanding at
(3)Operating leases include costs for compressors, drilling rigs, pressure pumping equipment, office space and other equipment under non-cancelable operating leases expiring through 2036.
(4)As of
(5)Our other significant contractual obligations include approximately
Future contributions to the pension and postretirement benefit plans are excluded from the table above. For further information regarding our pension and other postretirement benefit plans, we refer you to Note 13 to the consolidated financial statements included in this Annual Report and " Critical Accounting Policies and Estimates " below for additional information.
We refer you to Note 9 to the consolidated financial statements included in this Annual Report for a discussion of the terms of our debt.
We are subject to various litigation, claims and proceedings that arise in the
ordinary course of business, such as for alleged breaches of contract,
miscalculation of royalties, employment matters, traffic incidents, pollution,
contamination, encroachment on others' property or nuisance. We accrue for such
items when a liability is both probable and the amount can be reasonably
estimated. Management believes that current litigation, claims and proceedings,
individually or in aggregate and after taking into account insurance, are not
likely to have a material adverse impact on our financial position, results of
operations or cash flows, although it is possible that adverse outcomes could
have a material adverse effect on our results of operations or cash flows for
the period in which the effect of that outcome becomes reasonably
estimable. Many of these matters are in early stages, so the allegations and the
damage theories have not been fully developed, and are all subject to inherent
uncertainties; therefore, management's view may change in the future.
We are also subject to laws and regulations relating to the protection of the
environment. Environmental and cleanup related costs of a non-capital nature are
accrued when it is both probable that a liability has been incurred and when the
amount can be
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reasonably estimated. Management believes any future remediation or other compliance related costs will not have a material effect on our financial position, results of operations or cash flows.
For further information, we refer you to "Litigation" and "Environmental Risk" in Note 10 to the consolidated financial statements included in this Annual Report.
Supplemental Guarantor Financial Information
As discussed in Note 9 , inApril 2018 the Company entered into the 2018 credit facility. Pursuant to requirements under the indentures governing our senior notes, each 100% owned subsidiary that became a guarantor of the 2018 credit facility also became a guarantor of each of our senior notes (the "Guarantor Subsidiaries"). The Guarantor Subsidiaries also granted liens and security interests to support their guarantees under the 2018 credit facility but not of the senior notes. These guarantees are full and unconditional and joint and several among the Guarantor Subsidiaries. Certain of our operating units which are accounted for on a consolidated basis do not guarantee the 2018 credit facility and senior notes.
Upon the closing of the Mergers, discussed further in Note 2 to the consolidated financials included in this Annual Report, certain acquired entities owning oil and gas properties became guarantors to the 2018 credit facility.
The Company and the Guarantor Subsidiaries jointly and severally, and fully and
unconditionally, guarantee the payment of the principal and premium, if any, and
interest on the senior notes when due, whether at stated maturity of the senior
notes, by acceleration, by call for redemption or otherwise, together with
interest on the overdue principal, if any, and interest on any overdue interest,
to the extent lawful, and all other obligations of the Company to the holders of
the senior notes.
SEC Regulation S-X Rule 13-01 requires the presentation of "Summarized Financial
Information" to replace the "Condensed Consolidating Financial Information"
required under Rule 3-10. Rule 13-01 allows the omission of Summarized Financial
Information if assets, liabilities and results of operations of the Guarantors
are not materially different than the corresponding amounts presented in the
consolidated financial statements of the Company. The Parent and Guarantor
Subsidiaries comprise the material operations of the Company. Therefore, the
Company concluded that the presentation of the Summarized Financial Information
is not required as the Summarized Financial Information of the Company's
Guarantors is not materially different from our consolidated financial
statements.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The discussion and analysis of financial condition and results of operations are
based upon our consolidated financial statements, which have been prepared in
accordance with accounting principles generally accepted in the United
States . The preparation of these financial statements requires management to
make estimates and judgments that affect the amounts of assets, liabilities,
revenues and expenses and related disclosure of contingent assets and
liabilities. We evaluate our estimates on an on-going basis, based on historical
experience and on various other assumptions that are believed to be reasonable
under the circumstances. Actual results may differ from these estimates under
different assumptions or conditions. We believe the following describes
significant judgments and estimates used in the preparation of our consolidated
financial statements.
Natural Gas and
We utilize the full cost method of accounting for costs related to the
exploration, development and acquisition of natural gas and oil
properties. Under this method, all such costs (productive and nonproductive),
including salaries, benefits and other internal costs directly attributable to
these activities, are capitalized on a country-by-country basis and amortized
over the estimated lives of the properties using the units-of-production
method. These capitalized costs are subject to a quarterly ceiling test that
limits such pooled costs, net of applicable deferred taxes, to the aggregate of
the present value of future net revenues attributable to proved natural gas, oil
and NGL reserves discounted at 10% (standardized measure) plus the lower of cost
or market value of unproved properties. Any costs in excess of the ceiling are
written off as a non-cash expense. The expense may not be reversed in future
periods, even though higher natural gas, oil and NGL prices may subsequently
increase the ceiling. Companies using the full cost method are required to use
the average quoted price from the first day of each month from the previous 12
months, including the impact of derivatives designated for hedge accounting, to
calculate the ceiling value of their reserves. Prices used to calculate the
ceiling value of reserves were as follows:
December 31, 2021 December 31, 2020
Natural gas (per MMBtu) $ 3.60 $ 1.98
Oil (per Bbl) $ 66.56 $ 39.57
NGLs (per Bbl) $ 28.65 $ 10.27
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Using the average quoted prices above, adjusted for market differentials, our net book value of ourUnited States natural gas and oil properties did not exceed the ceiling amount atDecember 31, 2021 . We had no derivative positions that were designated for hedge accounting as ofDecember 31, 2021 . Future decreases in market prices, as well as changes in production rates, levels of reserves, evaluation costs excluded from amortization, future development costs and production costs may result in future non-cash impairments to our natural gas and oil properties. The net book value of our natural gas and oil properties exceeded the ceiling amount in each quarter of 2020 resulting in a total non-cash full cost ceiling test impairment of$2,825 million . We had no derivative positions that were designated for hedge accounting as ofDecember 31, 2020 . No impairment expense was recorded in 2020 or 2021 in relation to our natural gas and oil properties acquired from Montage. These properties were recorded at fair value as ofNovember 13, 2020 , in accordance with ASC Topic 820 - Fair Value Measurement. In the fourth quarter of 2020, pursuant toSEC guidance, we determined that the fair value of the properties acquired at the closing of the Montage Merger clearly exceeded the related full-cost ceiling limitation beyond a reasonable doubt and received a waiver from theSEC to exclude the properties acquired in the Montage Merger from the ceiling test calculation. This waiver was granted for all reporting periods through and including the quarter endingSeptember 30, 2021 , as long as we could continue to demonstrate that the fair value of properties acquired clearly exceeded the full cost ceiling limitation beyond a reasonable doubt in each reporting period. As part of the waiver received from theSEC , we were required to disclose what the full cost ceiling test impairment amounts for all periods presented in each applicable quarterly and annual filing would have been if the waiver had not been granted. The fair value of the properties acquired in the Montage Merger was based on future commodity market pricing for natural gas and oil pricing existing at the date of the Montage Merger, and we affirmed that there has not been a material decline to the fair value of these acquired assets since the Montage Merger. The properties acquired in the Montage Merger had an unamortized cost atDecember 31, 2020 of$1,087 million . Had we not received the waiver from theSEC , the impairment charge recorded would have been an additional$539 million for the year endedDecember 31, 2020 . Due to the improvement in commodity prices during 2021, no impairment charge would have been recorded in 2021 had the Montage natural gas and oil properties been included in the full cost ceiling test. Changes in natural gas, oil and NGL prices used to calculate the discounted future net revenues of our reserves affects both the present value of cash flows and the quantity of reserves. Our reserve base as ofDecember 31, 2021 was approximately 82% natural gas, 2% NGLs and 16% oil, and our standardized measure and reserve quantities as ofDecember 31, 2021 , were$18.73 billion and 21.1 Tcfe, respectively. Costs associated with unevaluated properties are excluded from our amortization base until we have evaluated the properties or impairment is indicated. The costs associated with unevaluated leasehold acreage and related seismic data, wells currently drilling and related capitalized interest are initially excluded from our amortization base. Leasehold costs are either transferred to our amortization base with the costs of drilling a well on the lease or are assessed at least annually for possible impairment or reduction in value. Our decision to withhold costs from amortization and the timing of the transfer of those costs into the amortization base involves judgment and may be subject to changes over time based on several factors, including our drilling plans, availability of capital, project economics and drilling results from adjacent acreage. AtDecember 31, 2021 , we had approximately$2,231 million of costs excluded from our amortization base, all of which related to our properties inthe United States . Inclusion of some or all of these costs in our properties inthe United States in the future, without adding any associated reserves, could result in non-cash ceiling test impairments. Proved natural gas, oil and NGL reserves are a major component of the full cost ceiling test. Natural gas, oil and NGL reserves cannot be measured exactly. Our estimate of natural gas, oil and NGL reserves requires extensive judgments of reservoir engineering data and projections of costs that will be incurred in developing and producing reserves and is generally less precise than other estimates made in connection with financial disclosures. Our reservoir engineers prepare our reserve estimates under the supervision of our management. Reserve estimates are prepared for each of our properties annually by the reservoir engineers assigned to the asset management team for that property. The reservoir engineering and financial data included in these estimates are reviewed by senior engineers, who are not part of the asset management teams, and by our Director of Reserves, who is the technical person primarily responsible for overseeing the preparation of our reserves estimates. Our Director of Reserves has more than 27 years of experience in petroleum engineering, including the estimation of natural gas and oil reserves, and holds a Bachelor of Science in Petroleum Engineering. Prior to joining us in 2018, our Director of Reserves served in various reservoir engineering roles forEP Energy Company ,El Paso Corporation , Cabot Oil & Gas Corporation, Schlumberger andH.J. Gruy & Associates , and is a member of theSociety of Petroleum Engineers . He reports to our Executive Vice President and Chief Operating Officer, who has more than 33 years of experience in petroleum engineering including the estimation of natural gas, oil and NGL reserves in multiple basins inthe United States , and holds a Bachelor of Science in Petroleum Engineering. Prior to joining Southwestern in 2017, our Chief Operating Officer served in various engineering and leadership roles for EP Energy 73
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Corporation,
We engage NSAI, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies, to independently audit our proved reserves estimates as discussed in more detail below. NSAI was founded in 1961 and performs consulting petroleum engineering services underTexas Board of Professional Engineers Registration No . F-002699. Within NSAI, the two technical persons primarily responsible for auditing our proved reserves estimates (1) have over 24 years and over 20 years of practical experience in petroleum geosciences and petroleum engineering, respectively; (2) have over 13 years and over 20 years of experience in the estimation and evaluation of reserves, respectively; (3) each has a college degree; (4) each is a Licensed Professional Geoscientist in theState of Texas or a Licensed Professional Engineer in theState of Texas ; (5) each meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by theSociety of Petroleum Engineers ; and (6) each is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applyingSEC and other industry reserves definitions and guidelines. The financial data included in the reserve estimates is also separately reviewed by our accounting staff. Our proved reserves estimates, as internally reviewed and audited by NSAI, are submitted for review and approval to our President and Chief Executive Officer. Finally, upon his approval, NSAI reports the results of its reserve audit to the Board of Directors, with whom final authority over the estimates of our proved reserves rests. A copy of NSAI's report has been filed as Exhibit 99.1 to this Annual Report. Proved developed reserves generally have a higher degree of accuracy in this estimation process, when compared to proved undeveloped and proved non-producing reserves, as production history and pressure data over time is available for the majority of our proved developed properties. Proved developed reserves accounted for 54% of our total reserve base as ofDecember 31, 2021 . Assigning monetary values to such estimates does not reduce the subjectivity and changing nature of such reserve estimates. The uncertainties inherent in the reserve estimates are compounded by applying additional estimates of the rates and timing of future production volumes and the costs that will be incurred in developing and producing the reserves. We cannot assure you that our internal controls sufficiently address the numerous uncertainties and risks that are inherent in estimating quantities of natural gas, oil and NGL reserves and projecting future rates of production and timing of development expenditures as many factors are beyond our control. We refer you to "Our proved natural gas, oil and NGL reserves are estimates that include uncertainties. Any material changes to these uncertainties or underlying assumptions could cause the quantities and net present value of our reserves to be overstated or understated" in Item 1A
,
"Risk Factors," of Part I of this Annual Report for a more detailed discussion of these uncertainties, risks and other factors.
In conducting its audit, the engineers and geologists of NSAI study our major properties in detail and independently develop reserve estimates. NSAI's audit consists primarily of substantive testing, which includes a detailed review of all operated proved developed properties plus all proved undeveloped locations. The proved developed properties included in the NSAI audit account for approximately 99% of the proved developed reserve volume and 99% of the proved developed present worth as ofDecember 31, 2021 . The proved undeveloped properties included in the NSAI audit account for 100% of the proved undeveloped reserve volume and 100% of the proved undeveloped present worth as ofDecember 31, 2021 . In the conduct of its audit, NSAI did not independently verify the data we provided to them with respect to ownership interests, natural gas, oil and NGL production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the properties and sales of production. NSAI has advised us that if, in the course of its audit, something came to its attention that brought into question the validity or sufficiency of any such information or data, NSAI did not rely on such information or data until it had satisfactorily resolved any questions relating thereto or had independently verified such information or data. OnJanuary 28, 2022 , NSAI issued its audit opinion as to the reasonableness of our reserve estimates for the year-endedDecember 31, 2021 stating that our estimated proved natural gas, oil and NGL reserves are, in the aggregate, reasonable and have been prepared in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by theSociety of Petroleum Engineers .
Business Combinations
We account for business combinations under the acquisition method of accounting.
Accordingly, we recognize amounts for identifiable assets acquired and
liabilities assumed equal to their estimated acquisition date fair values. We
make various assumptions in estimating the fair values of assets acquired and
liabilities assumed. As fair value is a market-based measurement, it is
determined based on the assumptions that market participants would use. The most
significant assumptions relate to the estimated fair values of proved and
unproved oil and natural gas properties. Fair value of proved natural gas and
oil properties as of the acquisition date was based on estimated proved natural
gas, oil and NGL reserves and related discounted net cash flows. Significant
inputs to the valuation include estimates of future production volumes, future
operating and development costs, future commodity prices and a weighted average
cost of capital rate. The market-based weighted average cost of capital rate is
subjected to additional project-specific risking factors. In addition, when
appropriate, we review comparable purchases and sales of natural
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gas and oil properties within the same regions, and use that data as a proxy for fair market value as this is an indication of the amount that a willing buyer and seller would enter into in exchange for such properties. Any excess of the acquisition price over the estimated fair value of net assets acquired is recorded as goodwill. Any excess of the estimated fair value of net assets acquired over the acquisition price is recorded in current earnings as a gain on bargain purchase. Deferred taxes are recorded for any differences between the assigned values and the tax basis of assets and liabilities. The Mergers qualified as business combinations, and as such, we estimated the fair values of the assets acquired and liabilities assumed as of respective acquisition dates. The 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 (exit price). Fair value measurements also utilize assumptions of market participants. We used discounted cash flow models and we made market assumptions as to future commodity prices, projections of estimated quantities of natural gas and oil reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. These assumptions represent Level 3 inputs, as defined in Note 8 - Fair Value Measurements. •We recorded the net assets acquired and liabilities assumed in the Montage Merger at their estimated fair value onNovember 13, 2020 of approximately$213 million .
•We recorded the net assets acquired and liabilities assumed in the Indigo
Merger at their estimated fair value on
•We recorded the net assets acquired and liabilities assumed in the GEPH Merger
at their estimated fair value on
We consider the estimated fair values above to be representative of the prices paid by typical market participants. These measurements resulted in no goodwill or bargain purchases being recognized.
Derivatives and Risk Management
We use fixed price swap agreements and options to reduce the volatility of earnings and cash flow due to fluctuations in the prices of certain commodities and interest rates. Our policies prohibit speculation with derivatives and limit agreements to counterparties with appropriate credit standings to minimize the risk of uncollectability. We actively monitor the credit status of our counterparties based on their credit ratings and credit default swap rates where applicable, and to date have not had any credit defaults associated with our transactions. In both 2021 and 2020, we financially protected 83% of our total production with derivatives. The primary risks related to our derivative contracts are the volatility in market prices and basis differentials for our production. However, the market price risk is generally offset by the gain or loss recognized upon the related transaction that is financially protected. All derivatives are recognized in the balance sheet as either an asset or a liability as measured at fair value other than transactions for which the normal purchase/normal sale exception is applied. Certain criteria must be satisfied for derivative financial instruments to be designated for hedge accounting. Accounting guidance for qualifying hedges allows an unsettled derivative's unrealized gains and losses to be recorded in either earnings or as a component of other comprehensive income until settled. In the period of settlement, we recognize the gains and losses from these qualifying hedges in gas sales revenues. The ineffective portion of those fixed price swaps are recognized in earnings. Gains and losses on derivatives that are not designated for hedge accounting treatment, or that do not meet hedge accounting requirements, are recorded as a component of gain (loss) on derivatives on the consolidated statements of operations. Accordingly, the gain (loss) on derivatives component of the statement of operations reflects the gains and losses on both settled and unsettled derivatives. We calculate gains and losses on settled derivatives as the summation of gains and losses on positions which have settled within the reporting period. As ofDecember 31, 2021 , none of our derivative contracts were designated for hedge accounting treatment. Changes in the fair value of unsettled derivatives that were not designated for hedge accounting treatment are recorded in gain (loss) on derivatives. See Note 6 to the consolidated financial statements included in this Annual Report for more information on our derivative position atDecember 31, 2021 . Future market price volatility could create significant changes to the derivative positions recorded in our consolidated financial statements. We refer you to " Quantitative and Qualitative Disclosures about Market Risk " in Item 7A of Part II of this Annual Report for additional information regarding our hedging activities.
Pension and Other Postretirement Benefits
As part of ongoing effort to reduce costs, we have elected to freeze our pension plan effectiveJanuary 1, 2021 . Employees that were participants in the pension plan prior toJanuary 1, 2021 will continue to receive the interest component of the plan but 75
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will no longer receive the service component. We have commenced the pension plan termination process, but the specific date for the completion of the process is unknown at this time and will depend on certain legal and regulatory requirements or approvals. As part of the termination process, we expect to distribute lump sum payments to or purchase annuities for the benefit of plan participants, which is dependent on the participants' elections. In addition, we expect to make a payment equal to the difference between the total benefits due under the plan and the total value of the assets available, which, as ofDecember 31, 2021 , was approximately$12 million . Our current funding policy is to continue to contribute amounts which are actuarially determined to provide the plan with sufficient assets to meet future benefit payment requirements and which are tax deductible. We are in the process of evaluating the impact of the termination and future settlement accounting on our consolidated financial statements and related disclosures. We record our prepaid or accrued benefit cost, as well as our periodic benefit cost, for our pension and other postretirement benefit plans using measurement assumptions that we consider reasonable at the time of calculation (see Note 13 to the consolidated financial statements included in this Annual Report for further discussion and disclosures regarding these benefit plans). Two of the assumptions that affect the amounts recorded are the discount rate, which estimates the rate at which benefits could be effectively settled, and the expected return on plan assets, which reflects the average rate of earnings expected on the funds invested. For theDecember 31, 2021 benefit obligation the initial discount rate assumed is 3.20%. This compares to an initial discount rate of 3.10% for the benefit obligation and periodic benefit cost recorded in 2021. For the 2022 periodic benefit cost, the expected return assumed was reduced from 5.10% to 0.10%, as the investment allocations have shifted from a balanced portfolio to short-term fixed-income assets in alignment with the plan termination process. Using the assumed rates discussed above, we recorded total benefit cost of$4 million in 2021 related to our pension and other postretirement benefit plans, which included a$2 million settlement adjustment. As ofDecember 31, 2021 , we recognized a liability of$25 million , compared to$46 million atDecember 31, 2020 , related to our pension and other postretirement benefit plans. During 2021, we made cash contributions totaling$12 million to fund our pension and other postretirement benefit plans.
Long-term Incentive Compensation
Our long-term incentive compensation plans consist of a combination of stock-based awards that derive their value directly or indirectly from our common stock price, and cash-based awards that are fixed in amount, but subject to meeting annual performance thresholds. InMarch 2020 , we issued our first long-term fixed cash-based awards. We account for long-term incentive compensation transactions using a fair value method and recognize an amount equal to the fair value of the stock-based awards and cash-based awards cost in either the consolidated statement of operations or capitalize the cost into natural gas and oil properties included in property and equipment. Costs are capitalized when they are directly related to the acquisition, exploration and development activities of our natural gas and oil properties. We use models to determine fair value of stock-based compensation, which requires significant judgment with respect to forfeitures, volatility and other factors. The performance cash awards granted in 2021 and 2020 include a performance condition determined annually by the Company. If we, in our sole discretion, determine that the threshold was not met, the amount for that vesting period will not vest and will be cancelled. Our stock-based compensation is classified as either an equity award or a liability award in accordance with generally accepted accounting principles. The fair value of an equity-classified award is determined at the grant date and is amortized on a straight-line basis over the vesting life of the award. The fair-value of a liability-classified award is determined on a quarterly basis through the final vesting date and is amortized based on the current fair value of the award and the percentage of vesting period incurred to date. See Note 14 to the consolidated financial statements included in this Annual Report for further discussion and disclosures regarding our long-term incentive compensation.
New Accounting Standards
Refer to Note 1 to the consolidated financial statements included in this Annual Report for further discussion of our significant accounting policies and for discussion of accounting standards that have been implemented in this report, along with a discussion of relevant accounting standards that are pending adoption.
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