SOUTHWESTERN ENERGY COMPANY The following updates information as toSouthwestern Energy Company's financial condition provided in our 2021 Annual Report and analyzes the changes in the results of operations between the three month periods endedMarch 31, 2022 and 2021. For definitions of commonly used natural gas and oil terms used in this Quarterly Report, please refer to the "Glossary of Certain Industry Terms" provided in our 2021 Annual Report. The following discussion contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those anticipated in forward-looking statements for many reasons, including the risks described in "Cautionary Statement About Forward-Looking Statements" in the forepart of this Quarterly Report and in Item 1A, "Risk Factors" in Part I and elsewhere in our 2021 Annual Report. You should read the following discussion with our consolidated financial statements and the related notes included in this Quarterly Report. OVERVIEW Background We are an independent energy company engaged in natural gas, oil and NGLs development, exploration 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 development and production of natural gas as well as associated NGLs and oil, with our ongoing operations focused on 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 one 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 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. 39
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Recent Financial and Operating Results
Significant first quarter 2022 operating and financial results include:
•Net loss of$2,675 million , or ($2.40 ) per diluted share, decreased compared to net income of$80 million , or$0.12 per diluted share, for the same period in 2021. Net loss decreased primarily as a$998 million increase in operating income was more than offset by a$3,736 million reduction resulting from the impact of improved forward pricing on our derivatives position,$3,063 million of which was unrealized. Excluding the change in derivatives position, net income increased$981 million in the first quarter of 2022, compared to the same period in 2021, primarily as a$998 million improvement in operating income was partially offset by a$2 million loss on the early extinguishment of debt recorded in the first quarter of 2022 and a$10 million increase in interest expense from the first quarter of 2022 as compared to the same period in 2021. •Operating income of$1,299 million increased compared to operating income of$301 million for the same period in 2021 on a consolidated basis. Operating income increased$1,871 million , as increased commodity pricing and natural gas production were only partially offset by increased operating costs of$873 million . •Net cash provided by operating activities of$972 million increased 180% from$347 million for the same period in 2021 which was mostly attributable to higher production due to our recently acquiredHaynesville assets coupled with improved commodity pricing. This increase was partially offset by an increased loss on settled derivatives combined with an increase in operating expenses associated with our recently acquiredHaynesville assets. •Total capital investment of$544 million in the first quarter of 2022 increased 105% from$266 million for the same period in 2021 due to the addition of the acquiredHaynesville assets. E&P •E&P operating income of$1,278 million in the first quarter of 2022 increased$983 million , compared to the same period in 2021, primarily as an$1,369 million increase in E&P operating revenues resulting from a$2.26 per Mcfe increase in our realized weighted average price per Mcfe (excluding derivatives) and an 156 Bcfe increase in production volumes was only partially offset by a$386 million increase in E&P operating costs and expenses. •Total net production of 425 Bcfe, which was comprised of 88% natural gas and 12% oil and NGLs, increased 58% from 269 Bcfe in the same period in 2021, primarily due to a 76% increase in our natural gas production which was driven by theHaynesville assets acquired from Indigo and GEPH inSeptember 2021 andDecember 2021 , respectively. •Excluding the effect of derivatives, our realized natural gas price of$4.50 per Mcfe increased 113%, our realized oil price of$86.30 per barrel increased 79% and our realized NGL price of$39.33 per barrel increased 72%, as compared to the same period in 2021. Excluding the effect of derivatives, our total weighted average realized price of$4.88 per Mcfe increased 86% from the same period in 2021.
•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 (defined below) 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 and optimizing the value of
our assets; 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.
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•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 executing and integrating 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 strive to deliver those benefits of strategic transactions to our business. 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 in the 2021 Annual Report. As such, we aim to monitor and seek ways to minimize the environmental impact of our operations. Additionally, 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 the first quarter of 2022, 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 development 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 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 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. 41
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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. Restructuring charges, interest expense, gain (loss)
on derivatives, gain (loss) on early extinguishment of debt and income taxes are
discussed on a consolidated basis.
E&P
For the three months ended
March 31,
(in millions) 2022 2021
Revenues $ 2,074 $ 705
Operating costs and expenses 796 (1) 410 (2)
Operating income $ 1,278 $ 295
Gain (loss) on derivatives, settled $
(695)
(1)Includes
(2)Includes
Operating Income (Loss)
•E&P segment operating income increased$983 million for the three months endedMarch 31, 2022 , compared to the same period in 2021. A$1,369 million increase in E&P operating revenues resulting from an 86% increase in our realized weighted average price per Mcfe (excluding derivatives) and a 58% increase in production volumes was only partially offset by a$386 million increase in E&P operating costs and expenses.
Revenues
The following illustrates the effects on sales revenues associated with changes in commodity prices and production volumes:
Three months ended
Natural
(in millions except percentages) Gas Oil NGLs Total
2021 sales revenues (1) $ 451 $ 80 $ 173 $ 704
Changes associated with prices 897 49 114 1,060
Changes associated with production volumes 342 (19) (15) 308
2022 sales revenues (2) $ 1,690 $ 110 $ 272 $ 2,072
Increase from 2021 275 % 38 % 57 % 194 %
(1)Excludes
(2)Excludes
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Production Volumes
For the three months ended March 31,
Production volumes: 2022 2021 Increase/(Decrease)
Natural Gas (Bcf)
Appalachia 210 214 (2)%
Haynesville (1) 166 - 100%
Total 376 214 76%
Oil (MBbls)
Appalachia 1,263 1,658 (24)%
Haynesville (1) 4 - 100%
Other 3 4 (25)%
Total 1,270 1,662 (24)%
NGL (MBbls)
Appalachia 6,919 7,577 (9)%
Other - 1 (100)%
Total 6,919 7,578 (9)%
Production volumes by area: (Bcfe)
Appalachia 259 269 (4)%
Haynesville (1) 166 - 100%
Total 425 269 58%
Production volumes by formation: (Bcfe)
Marcellus Shale 217 213 2%
Utica Shale 42 56 (25)%
Haynesville Shale (1) 105 - 100%
Bossier Shale (1) 61 - 100%
Total 425 269 58%
Production percentage:
Natural gas 88 % 79 %
Oil 2 % 4 %
NGL 10 % 17 %
(1)The Haynesville E&P assets were acquired through the Indigo Merger and the
GEPH Merger in
•E&P production volumes increased by 156 Bcfe for the three months endedMarch 31, 2022 , compared to the same period in 2021, due to the recent acquisitions of producing natural gas and oil properties inHaynesville from Indigo inSeptember 2021 and GEPH inDecember 2021 . Production of 166 Bcfe from these properties more than offset a 10 Bcfe decrease in Appalachia production, as compared to the same period in 2021, due to a higher capital allocation to our recently acquiredHaynesville assets.
•Oil and NGL production decreased 11% for the three months ended
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
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 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.
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For the three months ended
March 31,
2022 2021 Increase/(Decrease)
Natural Gas Price:
NYMEX Henry Hub Price ($/MMBtu) (1) $ 4.95 $ 2.69 84%
Discount to NYMEX (2) (0.45) (0.58) (22)%
Average realized gas price, excluding derivatives ($/Mcf)
$ 2.11 113% Gain on settled financial basis derivatives ($/Mcf) 0.01
0.19
Gain (loss) on settled commodity derivatives ($/Mcf) (1.51)
0.03
Average realized gas price, including derivatives ($/Mcf)
$ 2.33 29% Oil Price: WTI oil price ($/Bbl) (3)$ 94.29 $ 57.84 63% Discount to WTI (4) (7.99) (9.70) (18)% Average oil price, excluding derivatives ($/Bbl)$ 86.30 $ 48.14 79% Loss on settled derivatives ($/Bbl) (36.01)
(11.17)
Average oil price, including derivatives ($/Bbl)$ 50.29 $ 36.97 36% NGL Price: Average realized NGL price, excluding derivatives ($/Bbl)$ 39.33 $ 22.86 72% Loss on settled derivatives ($/Bbl) (12.25)
(6.75)
Average realized NGL price, including derivatives ($/Bbl)
$ 16.11 68% Percentage of WTI, excluding derivatives 42 % 40 % Total Weighted Average Realized Price: Excluding derivatives ($/Mcfe)$ 4.88 $ 2.62 86% Including derivatives ($/Mcfe)$ 3.24 $ 2.54 28%
(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 and fuel charges, and excludes financial basis derivatives.
(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 support 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 3, Quantitative and Qualitative Disclosures About Market Risk, and Note 8 to the consolidated financial statements, included in this Quarterly Report. 44
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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 277 $ (0.53)
2023 250 (0.47)
2024 46 (0.71)
2025 9 (0.64)
Total 582
Physical NYMEX Sales Arrangements - Natural Gas (1)
2022 621 $ (0.17)
2023 565 (0.10)
2024 391 (0.07)
2025 303 (0.04)
2026 138 -
2027 126 0.01
2028 125 0.01
2029 125 0.01
2030 47 -
Total 2,441
(1)Based on last day settlement prices from monthly futures contracts.
In addition to protecting basis, the table below presents the amount of our future production in which price is financially protected as ofMarch 31, 2022 : Remaining Full Year Full Year 2022 2023 2024 Natural gas (Bcf) 982 938 279 Oil (MBbls) 3,413 2,114 603 Ethane (MBbls) 4,142 1,308 - Propane (MBbls) 4,873 1,066 - Normal Butane (MBbls) 1,388 329 - Natural Gasoline (MBbls) 1,497 359 -
Total financial protection on future production (Bcfe) 1,074
969 283
We refer you to Note 8 of the consolidated financial statements included in
this Quarterly Report for additional details about our derivative instruments.
Operating Costs and Expenses
For the three months ended
March 31,
(in millions except percentages) 2022 2021 Increase/(Decrease)
Lease operating expenses $ 401 $ 250 60%
General & administrative expenses 39 35 11%
Merger-related expenses 25 1 2,400%
Restructuring charges - 6 (100)%
Taxes, other than income taxes 57 24 138%
Full cost pool amortization 269 90 199%
Non-full cost pool DD&A 5 4 25%
Total operating costs $ 796 $ 410 94%
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For the three months ended
March 31, Increase/
Average unit costs per Mcfe: 2022 2021 (Decrease)
Lease operating expenses (1) $ 0.94 $ 0.93 1%
General & administrative expenses $ 0.09 (2) $ 0.13 (3) (31)%
Taxes, other than income taxes $ 0.13 $ 0.09 44%
Full cost pool amortization $ 0.63 $ 0.33 91%
(1)Includes post-production costs such as gathering, processing, fractionation and compression.
(2)Excludes
(3)Excludes
Lease Operating Expenses
•Lease operating expenses per Mcfe increased
General and Administrative Expenses
•General and administrative expenses increased$4 million for the three months endedMarch 31, 2022 compared to the same period in 2021, primarily due to increased personnel costs associated with our expanded operations inHaynesville . General and administrative expenses decreased$0.04 per Mcfe or 31% primarily due to the increased volumes associated with the 2021 Haynesville acquisitions.
Merger-Related Expenses
•Beginning with the Montage Merger in 2020, we 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 three months endedMarch 31, 2022 and 2021:
For the three months ended
2022 2021
Indigo GEPH Merger Montage Merger
(in millions) Merger Total
Transition services $ - $ 18 $ 18 $ -
Professional fees (advisory, bank, legal, consulting) - 1 1 -
Contract buyouts, terminations and transfers - 2 2 -
Due diligence and environmental 1 - 1 -
Employee-related - 1 1 1
Other - 2 2 -
Total merger-related expenses $ 1 $ 24 $ 25 $ 1
We refer you to Note 2 of the consolidated financial statements included in this Quarterly 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 cash 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 three months endedMarch 31, 2021 and were substantially completed by the end of the first quarter of 2021.
See Note 3 of the consolidated financial statements included in this Quarterly Report for additional details about our restructuring charges.
Taxes, Other than Income Taxes
•On a per Mcfe basis, taxes, other than income taxes, 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$0.04 for the three months endedMarch 31, 2022 compared to the same period in 2021, primarily due to the impact of higher commodity pricing on our severance taxes inWest Virginia , which are 46
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calculated as fixed percentage of revenue net of allowable production expenses, and the impact of incremental severance and ad valorem taxes associated with our assets inLouisiana . Full Cost Pool Amortization •Our full cost pool amortization rate increased$0.30 per Mcfe for the three months endedMarch 31, 2022 , as compared to the same period in 2021, primarily as a result of our acquisitions of natural gas and oil properties inHaynesville . •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$2,228 million and$2,231 million atMarch 31, 2022 and atDecember 31, 2021 , respectively. The unevaluated costs excluded from amortization decreased slightly as the impact of$224 million of unevaluated capital invested during the period was more than offset by the evaluation of previously unevaluated properties totaling$227 million . Marketing For the three months ended March 31, Increase/ (in millions except volumes and percentages) 2022 2021 (Decrease) Marketing revenues$ 2,755 $ 996 177% Other operating revenues - 1 (100)% Marketing purchases 2,728 986 177% Operating costs and expenses 6 5 20% Operating income$ 21 $ 6 250% Volumes marketed (Bcfe) 538 345 56%
Percent natural gas production marketed from affiliated E&P 91 %
93 %
operations
Affiliated E&P oil and NGL production marketed 83 % 80 % Operating Income •Operating income for our Marketing segment increased$15 million for the three months endedMarch 31, 2022 , compared to the same period in 2021, primarily due to a$17 million increase in the marketing margin (discussed below) which was slightly offset by lower other operating revenues and slightly higher operating costs. •The margin generated from marketing activities was$27 million and$10 million for the three months endedMarch 31, 2022 and 2021, respectively. The marketing margin increased in 2022, compared to the same period in 2021, primarily due to increased volumes marketed and optimization of a larger transportation portfolio due to increased 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$1,759 million for the three months endedMarch 31, 2022 compared to the same period in 2021, primarily due to a 77% increase in the price received for volumes marketed and a 193 Bcfe increase in the volumes marketed. 47
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Operating Costs and Expenses
•Operating costs and expenses for the marketing segment increased by$1 million for the three months endedMarch 31, 2022 compared to the same period in 2021, primarily due to increased personnel costs associated with the 2021 Haynesville acquisitions. Consolidated Interest Expense For the three months ended March 31, (in millions except percentages) 2022 2021 Increase/(Decrease) Gross interest expense: Senior notes$ 58 $ 44 32% Credit arrangements 10 6 67% Amortization of debt costs 3 3 -% Total gross interest expense 71 53 34% Less: capitalization (30) (22) 36% Net interest expense$ 41 $ 31 32% •Interest expense related to our senior notes increased for the three months endedMarch 31, 2022 , compared to the same period in 2021, as a result of the assumption of Indigo Notes, which were exchanged for$700 million aggregate principal amount of our 5.375% Senior Notes due 2029, theSeptember 2021 public offering of$1,200 million aggregate principal amount of our 5.375% Senior Notes due 2030, and theDecember 2021 public offering of$1,150 million aggregate principal amount of our 4.75% Senior Notes due 2032.
•Capitalized interest increased for the three months ended
•Capitalized interest as a percentage of gross interest expense remained flat
for the three months ended
•We refer you to Note 11 to the consolidated financial statements included
in this Quarterly Report for additional details about our debt and our financing
activities.
Gain (Loss) on Derivatives
For the three months ended
March 31,
(in millions) 2022 2021
Loss on unsettled derivatives $ (3,237) $ (169)
Loss on settled derivatives (695) (22)
Non-performance risk adjustment 5 -
Loss on derivatives $ (3,927) $ (191) We refer you to Note 8 to the consolidated financial statements included in this Quarterly Report for additional details about our gain (loss) on derivatives.
Gain/Loss on Early Extinguishment of Debt
For the three months endedMarch 31, 2022 , we recorded a loss on early debt extinguishment of$2 million as a result of our repurchase of$221 million in aggregate principal amount of our outstanding senior notes for$223 million . Included as part of the repurchase was the full redemption of our 4.10% Senior Notes dueMarch 2022 with an aggregate principal amount retired of$201 million .
See Note 11 to the consolidated financial statements of this Quarterly Report for more information on our long-term debt.
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Income Taxes
For the three months ended March 31,
(in millions except percentages) 2022 2021
Income tax expense $ 4 $ -
Effective tax rate 0 % 0 %
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 of the first quarter of 2022, 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.
We expect to continue a full valuation allowance on our deferred tax assets
until there is sufficient evidence to support the reversal of all or some
portion of the allowance. However, if current commodity prices are sustained and
absent any additional objective negative evidence, it is reasonably possible
that sufficient positive evidence will exist within the next 12 months to adjust
the current valuation allowance position. Exact timing and amount of the
adjustment to the valuation allowance is unknown at this time.
Due to the issuance of common stock associated with the Indigo Merger, as
discussed in Note 2 , 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. At March 31, 2022 , 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 remaining U.S. tax attributes may be further limited.
New Accounting Standards Implemented in this Report
Refer to Note 17 to the consolidated financial statements of this Quarterly Report for a discussion of new accounting standards that have been implemented.
New Accounting Standards Not Yet Implemented in this Report
Refer to Note 17 to the consolidated financial statements of this Quarterly Report for a discussion of new accounting standards that have not yet been implemented.
LIQUIDITY AND CAPITAL RESOURCES
On April 8, 2022 we entered into the 2022 credit facility which extends the
maturity of our existing credit facility through April 2027 . The 2022 credit
facility has an aggregate maximum revolving credit amount and borrowing base of
$3.5 billion , elected commitments of $2.0 billion and has provisions that
provide the ability to convert our secured credit facility to an unsecured
credit facility if we are able to achieve investment grade status as deemed by
the relevant rating agencies. We refer to the 2018 credit facility throughout
this Quarterly Report as it was in effect as of the quarter ended March 31,
2022 .
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 March 31, 2022 , we had approximately $1.7
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. As of March 31, 2022 we had borrowings under the term loan of $549
million . The remaining $351 million of incremental term loan capacity remains
accessible through November 2022 and provides access to another
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secured debt capital source for liquidity purposes. The flexibility to access this term loan capacity throughNovember 2022 is included in our 2022 credit facility. Our flexibility to access incremental secured debt capital is derived from our excess asset collateral value above the$3.5 billion maximum revolving credit amount and borrowing base of our 2022 credit facility and the elected$2.0 billion of aggregate commitments from our bank group. Our ability to issue secured debt is governed by the limitations of our 2022 credit facility as well as our secured debt capacity (as defined by our senior note indentures) which was$6.5 billion as ofMarch 31, 2022 , based on 25% of adjusted consolidated net tangible assets. If we were to realize a return to investment grade ratings and the subsequent conversion of our secured credit facility to an unsecured credit facility, we would expect to have access to additional liquidity capital, either by increasing commitments to the 2022 credit facility up to the$3.5 billion aggregate size or otherwise on a similarly unsecured basis, given our current excess asset collateral value and credit quality. Throughout 2022, we expect to continue to generate free cash flow, which is defined as cash flow from operations, net of changes in working capital, in excess of our expected capital investments, and we intend to utilize free cash flow to pay down our debt. We refer you to Note 11 to the consolidated financial statements included in this Quarterly Report and the section below under "Credit Arrangements and Financing Activities" for additional discussion of our 2022 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 "Risk Factors" in Item 1A of our 2021 Annual Report 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 support 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 remainder of our expected production at favorable prices. We again refer you to "Risk Factors" in Item 1A of our 2021 Annual Report. 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 flows 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 and our subsidiaries' assets (taken as a whole). The permitted lien provisions in the 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 ofMarch 31, 2022 , we had$174 million of borrowings on our 2018 credit facility and$147 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 11 to the consolidated financial statements included in this Quarterly Report for additional discussion of our 2018 credit facility.
As of
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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 11 of the consolidated financial statements included in this Quarterly Report for additional discussion of the covenant requirements of our 2018 credit facility. InApril 2022 , we entered into an amended and restated credit agreement that replaces the 2018 credit facility (the "2022 credit facility") with a group of banks that, as amended, has a maturity date ofApril 2027 . The 2022 credit facility has an aggregate maximum revolving credit amount and borrowing base of$3.5 billion and elected commitments of$2.0 billion . 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 2022 credit facility is secured by substantially all of our assets and our subsidiaries' assets (taken as a whole). The permitted lien provisions in the senior note indentures currently limit liens securing indebtedness to the greater of$2.0 billion or 25% of adjusted consolidated net tangible assets, which was$6.5 billion as ofMarch 31, 2022 . The 2022 credit facility utilizes the SOFR index rates for purposes of calculating interest expense. The 2022 credit facility has certain financial covenant requirements that currently mirror those of our 2018 credit facility, but provide certain fall away features should we receive an Investment Grade Rating (defined as an index debt rating of BBB- or higher with S&P, Baa3 or higher with Moody's, or BBB- or higher with Fitch) and meet other criteria in the future. We refer you to Note 11 to the consolidated financial statements included in this Quarterly Report for additional discussion of our 2022 credit facility. The credit status of the financial institutions participating in our 2022 credit facility could adversely impact our ability to borrow funds under the 2022 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 11 to the consolidated financial statements included in this Quarterly Report for additional discussion of our revolving credit facility. 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 ofMarch 31, 2022 , we had borrowings under the Term Loan of$549 million .
Other key financing activities over the last 3 months are as follows:
Debt Repurchases
•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, coupled with the amendment and restatement of our credit facility onApril 8, 2022 , the only debt balance scheduled to become due prior to 2025 is$15 million of our Term Loan principal. •InMarch 2022 , we repurchased$5 million of our 8.375% Senior Notes due 2028 and$15 million of our 7.75% Senior Notes due 2027, resulting in a$2 million loss on debt extinguishment. As ofApril 26, 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, as our 2025 senior notes are subject to ratings driven changes. 51
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