SOUTHWESTERN ENERGY COMPANY The following updates information as toSouthwestern Energy Company's financial condition provided in our Annual Report on Form 10-K for the year endedDecember 31, 2021 (the "2021 Annual Report") and analyzes the changes in the results of operations between the three and six month periods endedJune 30, 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. 39
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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 and
Haynesville 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 in Pennsylvania , West Virginia,
Ohio and Louisiana . Our operations in Pennsylvania , West Virginia and Ohio ,
which we refer to as "Appalachia," are focused on the Marcellus Shale , the Utica
and the Upper Devonian unconventional natural gas and liquids reservoirs. Our
operations in Louisiana , which we refer to as "Haynesville ," are primarily
focused on the Haynesville and Bossier natural gas reservoirs. We also have
drilling rigs located in Appalachia and Haynesville , and we provide certain
oilfield products and services, principally serving our E&P operations through
vertical integration. Over the past two years, we have completed three strategic
E&P acquisitions which have added scale to our operations:
•On November 13, 2020 , we closed on the Montage Merger, which increased our
footprint in West Virginia and Pennsylvania and expanded our operations into
Ohio .
•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.
Recent Financial and Operating Results
Significant second quarter 2022 operating and financial results include:
•Net income of$1,173 million , or$1.05 per diluted share, increased compared to a net loss of$609 million , or ($0.90 ) per diluted share, for the same period in 2021. Net income increased primarily from higher operating income of$1,838 million associated with higher production and stronger realized pricing. The increase in operating income was partially offset by an increased income tax provision of$26 million , increased interest expense of$18 million associated with the public offering of multiple tranches of senior notes due 2029, 2030 and 2032 during the second half of 2021, a loss on debt extinguishment of$4 million and an increased loss of$8 million on our derivative positions as a result of improved forward pricing. •Operating income of$2,131 million increased compared to operating income of$293 million for the same period in 2021 on a consolidated basis. Operating income improved as a$3,088 million increase in operating revenues more than offset increased operating costs of$1,250 million associated with increased pricing and production. •Net cash provided by operating activities of$427 million increased 58% from$270 million for the same period in 2021 which was mostly attributable to higher production associated with the late 2021 acquisitions of theHaynesville 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 ourHaynesville assets. •Total capital investment of$585 million in the second quarter of 2022 increased 126% from$259 million for the same period in 2021 primarily due to the increased drilling and completion activity associated with ourHaynesville assets. 40
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E&P
•E&P operating income of$2,120 million in the second quarter of 2022 increased$1,834 million , compared to the same period in 2021, primarily as a$2,225 million increase in E&P operating revenues resulting from a$4.14 per Mcfe increase in our realized weighted average price per Mcfe (excluding derivatives) and a 162 Bcfe increase in production volumes was only partially offset by a$391 million increase in E&P operating costs and expenses. •Total net production of 438 Bcfe, which was comprised of 87% natural gas and 13% oil and NGLs, increased 59% from 276 Bcfe in the same period in 2021, primarily due to a 75% 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$6.48 per Mcfe increased 238%, our realized oil price of$100.29 per barrel increased 74% and our realized NGL price of$40.07 per barrel increased 72%, as compared to the same period in 2021. Excluding the effect of derivatives, our total weighted average realized price of$6.69 per Mcfe increased 162% from the same period in 2021.
•E&P segment invested
Outlook
Our primary focus in 2022 is to maintain our annual 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. Additionally, we plan to execute on our share repurchase program in order to return value to our shareholders (subject to market and business conditions as further discussed below).
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 working to lower our leverage ratio and total debt; extend the weighted average years to maturity of our debt; lower our cost of debt; deploy hedges to protect against downward price movement; cover our costs and meeting other financial commitments; and maintain 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 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, create logistical synergies and cost economies, 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. 41
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COVID-19
During the first half 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. 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 For the six months ended June June 30, 30, (in millions) 2022 2021 2022 2021 Revenues$ 2,929 $ 704 $ 5,003 $ 1,409 Operating costs and expenses 809 (1) 418 (2) 1,605 (1) 828 (2) Operating income$ 2,120 $ 286
Loss on derivatives, settled$ (1,601) $
(99)
(1)Includes
(2)Includes$1 million and$7 million in restructuring charges for the three and six months endedJune 30, 2021 , respectively, and$3 million and$4 million in merger-related expenses for the three and six months endedJune 30, 2021 , respectively.
Operating Income (Loss)
•E&P segment operating income increased
•E&P segment operating income increased$2,817 million for the six months endedJune 30, 2022 , compared to the same period in 2021. A$3,594 million increase in E&P operating revenues resulting from a 125% increase in our realized weighted average price per Mcfe (excluding derivatives) and a 58% increase in production volumes was only partially offset by a$777 million increase in E&P operating costs and expenses. 42
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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 $ 421 $ 105 $ 178 $ 704
Changes associated with prices 1,749 58 130 1,937
Changes associated with production volumes 315 (27) 2 290
2022 sales revenues (1) $ 2,485 $ 136 $ 310 $ 2,931
Increase from 2021 490 % 30 % 74 % 316 %
Six months ended June 30,
Natural
(in millions except percentages) Gas Oil NGLs Total
2021 sales revenues (2) $ 872 $ 185 $ 351 $ 1,408
Changes associated with prices 2,644 107 245 2,996
Changes associated with production volumes 659 (46) (14) 599
2022 sales revenues $ 4,175 $ 246 $ 582 $ 5,003
Increase from 2021 379 % 33 % 66 % 255 %
(1)Excludes
(2)Excludes
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Production Volumes
For the three months ended June 30, For the six months ended June 30,
Production volumes: 2022 2021 Increase/(Decrease) 2022 2021 Increase/(Decrease)
Natural Gas (Bcf)
Appalachia 214 219 (2)% 424 433 (2)%
Haynesville (1) 169 - 100% 335 - 100%
Total 383 219 75% 759 433 75%
Oil (MBbls)
Appalachia 1,354 1,826 (26)% 2,617 3,484 (25)%
Haynesville (1) 7 - 100% 11 - 100%
Other 2 5 (60)% 5 9 (44)%
Total 1,363 1,831 (26)% 2,633 3,493 (25)%
NGL (MBbls)
Appalachia 7,738 7,665 1% 14,657 15,242 (4)%
Other - 1 (100)% - 2 (100)%
Total 7,738 7,666 1% 14,657 15,244 (4)%
Production volumes by area: (Bcfe)
Appalachia 269 276 (3)% 528 545 (3)%
Haynesville (1) 169 - 100% 335 - 100%
Total 438 276 59% 863 545 58%
Production volumes by
formation: (Bcfe)
Marcellus Shale 226 242 (7)% 443 455 (3)%
Utica Shale 43 34 26% 85 90 (6)%
Haynesville Shale (1) 105 - 100% 210 - 100%
Bossier Shale (1) 64 - 100% 125 - 100%
Total 438 276 59% 863 545 58%
Production percentage: Natural gas 87 % 79 % 88 % 79 % Oil 2 % 4 % 2 % 4 % NGL 11 % 17 % 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 162 Bcfe for the three months endedJune 30, 2022 , compared to the same period in 2021, due to the acquisitions of producing natural gas and oil properties inHaynesville from Indigo inSeptember 2021 and GEPH inDecember 2021 . Production of 169 Bcfe from these properties more than offset a 7 Bcfe decrease in Appalachia production, as compared to the same period in 2021, due to a higher capital allocation to ourHaynesville assets. •E&P production volumes increased by 318 Bcfe for the six months endedJune 30, 2022 , compared to the same period in 2021, due to the acquisitions of producing natural gas and oil properties inHaynesville from Indigo inSeptember 2021 and GEPH inDecember 2021 . Production of 335 Bcfe from these properties more than offset a 17 Bcfe decrease in Appalachia production, as compared to the same period in 2021, due to a higher capital allocation to ourHaynesville assets. •Oil and NGL production decreased 4% and 8% for the three and six months endedJune 30, 2022 , respectively, compared to the same periods in 2021, primarily due to a higher capital allocation to ourHaynesville assets. 44
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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.
For the three months ended June For the six months ended June
30, 30,
2022 2021 Increase/(Decrease) 2022 2021 Increase/(Decrease)
Natural Gas Price:
NYMEX Henry Hub Price ($/MMBtu) (1) $ 7.17 $ 2.83 153% $ 6.06 $ 2.76 120%
Discount to NYMEX (2) (0.69) (0.91) (24)% (0.56) (0.74) (24)%
Average realized gas price, excluding $ 6.48 $ 1.92 238% $ 5.50 $ 2.02 172%
derivatives ($/Mcf) Gain on settled financial basis 0.06 0.03 0.04 0.11 derivatives ($/Mcf) Gain (loss) on settled commodity (3.86) (0.06) (2.70) (0.02) derivatives ($/Mcf) Average realized gas price, including$ 2.68 $ 1.89 42%$ 2.84 $ 2.11 35% derivatives ($/Mcf) Oil Price: WTI oil price ($/Bbl) (3)$ 108.41 $ 66.07 64%$ 101.35 $ 61.96 64% Discount to WTI (4) (8.12) (8.57) (5)% (7.81) (8.92) (12)% Average oil price, excluding$ 100.29 $ 57.50 74%$ 93.54 $ 53.04 76% derivatives ($/Bbl) Loss on settled derivatives ($/Bbl) (43.35) (19.13) (39.81) (15.34) Average oil price, including$ 56.94 $ 38.37 48%$ 53.73 $ 37.70 43% derivatives ($/Bbl) NGL Price: Average realized NGL price, excluding$ 40.07 $ 23.24 72%$ 39.72 $ 23.05
72%
derivatives ($/Bbl) Loss on settled derivatives ($/Bbl) (10.84) (7.37) (11.50) (7.06) Average realized NGL price, including$ 29.23 $ 15.87 84%$ 28.22 $ 15.99 76% derivatives ($/Bbl) Percentage of WTI, excluding 37 % 35 % 39% 37% derivatives Total Weighted Average Realized Price: Excluding derivatives ($/Mcfe)$ 6.69 $ 2.55 162%$ 5.80 $ 2.58
125%
Including derivatives ($/Mcfe)$ 3.04 $ 2.20 38%$ 3.14 $ 2.36
33%
(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. 45
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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 182 $ (0.53)
2023 281 (0.50)
2024 46 (0.71)
2025 9 (0.64)
Total 518
Physical NYMEX Sales Arrangements - Natural Gas (1)
2022 439 $ (0.13)
2023 645 (0.08)
2024 438 (0.08)
2025 312 (0.05)
2026 159 (0.02)
2027 146 (0.02)
2028 146 (0.02)
2029 125 0.01
2030 47 -
Total 2,457
(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 ofJune 30, 2022 : Remaining Full Year Full Year Full Year 2022 2023 2024 2025 Natural gas (Bcf) 648 938 279 - Oil (MBbls) 2,313 2,183 749 41 Ethane (MBbls) 2,782 1,308 - - Propane (MBbls) 3,227 1,286 73 - Normal Butane (MBbls) 929 347 - - Natural Gasoline (MBbls) 1,001 359 - - Total financial protection on future production (Bcfe) 710 971 284 -
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 For the six months ended June
June 30, 30,
(in millions except
percentages) 2022 2021 Increase/(Decrease) 2022 2021 Increase/(Decrease)
Lease operating expenses $ 425 $ 260 63% $ 826 $ 510 62%
General & administrative
expenses 31 30 3% 70 65 8%
Merger-related expenses 2 3 (33)% 27 4 575%
Restructuring charges - 1 (100)% - 7 (100)%
Taxes, other than income taxes 65 27 141% 122 51 139%
Full cost pool amortization 283 94 201% 552 184 200%
Non-full cost pool DD&A 3 3 -% 8 7 14%
Total operating costs $ 809 $ 418 94% $ 1,605 $ 828 94%
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For the three months ended For the six months ended June
June 30, Increase/ 30, Increase/
Average unit costs per Mcfe: 2022 2021 (Decrease) 2022 2021 (Decrease)
Lease operating expenses (1) $ 0.97 $ 0.94 3% $ 0.96 $ 0.94 2%
General & administrative (2) (3) (2) (3)
expenses $ 0.07 $ 0.11 (36)% $ 0.08 $ 0.12 (33)%
Taxes, other than income taxes $ 0.15 $ 0.10 50% $ 0.14 $ 0.09 56%
Full cost pool amortization $ 0.65 $ 0.34 91% $ 0.64 $ 0.34 88%
(1)Includes post-production costs such as gathering, processing, fractionation and compression.
(2)Excludes
(3)Excludes$3 million and$4 million in merger-related expenses for the three and six months endedJune 30, 2021 , respectively, and$1 million and$7 million in restructuring charges in for the three and six months endedJune 30, 2021 , respectively. Lease Operating Expenses •Lease operating expenses per Mcfe increased$0.03 and$0.02 per Mcfe for the three and six months endedJune 30, 2022 , respectively, compared to the same periods in 2021, primarily due to increased costs associated with gathering fees, and the impact of increased commodity pricing on fuel and electricity costs.
General and Administrative Expenses
•General and administrative expenses increased$1 million for the three months endedJune 30, 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 36% primarily due to the increased volumes associated with the 2021 Haynesville acquisitions. •General and administrative expenses increased$5 million for the six months endedJune 30, 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 33% 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 tables below present the charges incurred for our merger-related activities for the three and six months endedJune 30, 2022 and 2021: For the three months ended June 30, 2022 2021 Indigo GEPH Merger Montage Merger Indigo Merger (in millions) Merger Total Total
Professional fees (advisory, bank, $ - $ -
$ - $ 1 $ 2$ 3
legal, consulting)
Contract buyouts, terminations and 1 - 1 - - -
transfers
Due diligence and environmental - 1 1 - - -
Total merger-related expenses
$ 2 $ 1 $ 2$ 3 For the six months ended June 30, 2022 2021 Indigo GEPH Merger Montage Merger Indigo Merger
(in millions) Merger Total Total Transition services $ - $ 18$ 18 $ - $ - $ - Professional fees (advisory, bank, - 1 1 1 2 3
legal, consulting)
Contract buyouts, terminations and 1 2 3 - - -
transfers
Due diligence and environmental 1 1 2 - - - Employee-related - 1 1 1 - 1 Other - 2 2 - - - Total merger-related expenses$ 2 $ 25$ 27 $ 2 $ 2$ 4
We refer you to Note 2 of the consolidated financial statements included in this Quarterly Report for additional details about the Mergers.
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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 six months endedJune 30, 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$0.05 for the three and six months endedJune 30, 2022 , compared to the same periods in 2021, primarily due to the impact of higher commodity pricing on our severance taxes inWest Virginia , which are 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$0.31 and$0.30 per Mcfe for the three and six months endedJune 30, 2022 , respectively, as compared to the same periods 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$2,256 million and$2,231 million atJune 30, 2022 and atDecember 31, 2021 , respectively. The unevaluated costs excluded from amortization increased as the impact of$577 million of unevaluated capital invested during the period more than offset the evaluation of previously unevaluated properties totaling$552 million . Marketing For the three months ended For the six months ended June June 30, 30, (in millions except volumes and Increase/ Increase/ percentages) 2022 2021 (Decrease) 2022 2021 (Decrease) Marketing revenues$ 4,023 $ 983 309%$ 6,778 $ 1,979 242% Other operating revenues - - -% - 1 (100)% Marketing purchases 4,006 969 313% 6,734 1,955 244% Operating costs and expenses 6 7 (14)% 12 12 -% Operating income$ 11 $ 7 57%$ 32 $ 13 146% Volumes marketed (Bcfe) 577 343 68% 1,115 688 62% Percent natural gas production 94 % 97 % 93 % 95 % marketed from affiliated E&P operations Affiliated E&P oil and NGL production 88 % 83 % 86 % 81 % marketed Operating Income •Operating income for our Marketing segment increased$4 million for the three months endedJune 30, 2022 , compared to the same period in 2021, primarily due to a$3 million increase in the marketing margin (discussed below) and slightly lower operating costs. 48
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•Operating income for our Marketing segment increased$19 million for the six months endedJune 30, 2022 , compared to the same period in 2021, primarily due to a$20 million increase in the marketing margin (discussed below) which was slightly offset by lower other operating revenues. •The margin generated from marketing activities was$17 million and$14 million for the three months endedJune 30, 2022 and 2021, respectively and$44 million and$24 million for the six months endedJune 30, 2022 and 2021, respectively. The marketing margin increased for the three and six months endedJune 30, 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$3,040 million and$4,799 million for the three and six months endedJune 30, 2022 , respectively, as compared to the same periods in 2021. The increases were primarily due to 143% and 111% increases in the prices received for volumes marketed for the three and six months endedJune 30, 2022 , respectively, and 234 Bcfe and 427 Bcfe increases in the volumes marketed for the three and six months endedJune 30, 2022 , respectively, as compared to the same periods in 2021.
Operating Costs and Expenses
•Operating costs and expenses for the marketing segment decreased by$1 million for the three months endedJune 30, 2022 due to a$1 million decrease in depreciation, depletion and amortization ("DD&A"), and remained flat for the six months endedJune 30, 2022 as a$2 million increase in personnel-related costs due to the 2021 Haynesville acquisitions was offset by$2 million of decreased DD&A, as compared to the same periods in 2021. Consolidated Interest Expense For the three months ended For the six months ended June 30, June 30, (in millions except percentages) 2022 2021 Increase/(Decrease) 2022 2021 Increase/(Decrease) Gross interest expense: Senior notes$ 60 $ 43 40%$ 118 $ 87 36% Credit arrangements 13 5 160% 23 11 109% Amortization of debt costs 4 3 33% 7 6 17% Total gross interest expense 77 51 51% 148 104 42% Less: capitalization (29) (21) 38% (59) (43) 37% Net interest expense$ 48 $ 30 60%$ 89 $ 61 46% •Interest expense related to our senior notes increased for the three and six months endedJune 30, 2022 , compared to the same periods 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 and six months endedJune 30, 2022 , as compared to the same periods in 2021, primarily due to the incremental capitalized interest associated with ourHaynesville unevaluated properties. •Capitalized interest as a percentage of gross interest expense decreased slightly for the three and six months endedJune 30, 2022 , compared to the same periods in 2021, primarily related to a smaller percentage change in our unevaluated natural gas and oil properties balance as compared to the larger percentage increase in our gross interest expense over the same period. •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. 49
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Gain (Loss) on Derivatives
For the three months ended For the six months ended June
June 30, 30,
(in millions) 2022 2021 2022 2021
Gain (loss) on unsettled derivatives $ 718 $ (772) $ (2,519) $ (941)
Loss on settled derivatives (1,601) (99) (2,296) (121)
Non-performance risk adjustment 4 - 9 -
Loss on derivatives $ (879) $ (871) $ (4,806) $ (1,062) 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 endedJune 30, 2022 , we recorded a loss on early debt extinguishment of$4 million as a result of our repurchase of$45 million in aggregate principal amount of our outstanding senior notes for$49 million . For the six months endedJune 30, 2022 , we recorded a loss on early debt extinguishment of$6 million as a result of our repurchase of$65 million in aggregate principal amount of our outstanding senior notes for$71 million . We also fully redeemed 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.
Income Taxes
For the three months ended June For the six months ended June
30, 30,
(in millions except percentages) 2022 2021 2022 2021
Income tax expense $ 26 $ - $ 30 $ -
Effective tax rate 2 % 0 % (2) % 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 second 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 June 30, 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.
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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
We depend primarily on funds generated from our operations, our 2022 credit
facility, our cash and cash equivalents balance and capital markets as our
primary sources of liquidity. On April 8, 2022 we extended the maturity and
restated our 2018 credit facility through April 2027 (the "2022 credit
facility"). In connection with entering into our 2022 credit facility, the banks
participating in our 2022 credit facility increased our borrowing base to $3.5
billion and agreed to provide aggregate commitments of $2.0 billion and agreed
to updated terms 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. At June 30, 2022 , we had
approximately $1.5 billion of total available liquidity, which exceeds our
currently modeled needs as we remain committed to our strategy of capital
discipline.
Effective August 4, 2022 , we elected to temporarily increase by $500 million our
commitments under the 2022 credit facility in the form of an additional tranche
of short-term revolving commitments. This new tranche of short-term revolving
commitments, effective through April 30, 2023 , provides incremental liquidity to
help us manage potential temporary working capital draws related to our 2022
hedge position. Due to our level of hedged natural gas production this year and
the inherent timing difference between monthly hedge settlements and the
corresponding physical sales receipts, a sharp month-over-month increase in
natural gas prices can cause temporary working capital draws. The capital
outlays are temporary because the physical sales receipts typically more than
offset the hedge settlements. This new short-term tranche of our credit facility
represents a proactive measure consistent with our established risk management
procedures. At current forward strip prices, we do not expect to draw upon this
new tranche, with our existing $2 billion long-term revolving commitments
expected to be sufficient for our liquidity needs.
In conjunction with the GEPH Merger, we amended our 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 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 June 30,
2022 we had borrowings under the term loan of $547 million . The remaining $353
million of incremental term loan capacity remains accessible through November
2022 and provides access to another secured debt capital source for liquidity
purposes. The flexibility to access this term loan capacity through November
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 revolving commitments and the additional tranche of $500
million short-term revolving 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 $7.1 billion as of June 30, 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 beyond our $2.0 billion elected aggregate revolving
commitments, 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. 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.
In June 2022 , we announced a share repurchase program, under which we have been
authorized to repurchase up to $1 billion of our outstanding common stock
beginning June 21, 2022 and continuing through and including December 31, 2023 .
We intend to fund the stock repurchases from available working capital and cash
provided by operating activities. The timing, as well as the number and value of
shares repurchased under the program, will be determined at our discretion and
includes a variety of factors, including our assessment of the intrinsic value
of our common stock, the market price of our common stock, general market and
economic conditions, available liquidity, compliance with our debt and other
agreements, applicable legal requirements and other considerations. The exact
number of shares to be repurchased is not guaranteed, and the program may be
suspended, modified, or discontinued at any time without prior notice. As of
June 30, 2022 , we have repurchased approximately 2.8 million shares at an
average share price of $7.10 for a total cost of approximately $20 million .
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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. While we expect to use a portion of this free cash flow to fund our share repurchase program as discussed above, we intend to prioritize the use of free cash flow to pay down our debt in order to achieve our debt and leverage targets. 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 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, as ofJune 30, 2022 , elected commitments of$2.0 billion . EffectiveAugust 4, 2022 , we elected to temporarily increase by$500 million our commitments under the 2022 credit facility in the form of an additional tranche of short-term revolving commitments. This new tranche of short-term revolving commitments, effective throughApril 30, 2023 , provides incremental liquidity to help us manage potential temporary working capital draws related to our 2022 hedge position. Due to our level of hedged natural gas production this year and the inherent timing difference between monthly hedge settlements and the corresponding physical sales receipts, a sharp month-over-month increase in natural gas prices can cause temporary working capital draws. The capital outlays are temporary because the physical sales receipts typically more than offset the hedge settlements. This new short-term tranche of our credit facility represents a proactive measure consistent with our established risk management procedures. At current forward strip prices, we do not expect to draw upon this new tranche, with our existing$2 billion long-term revolving commitments expected to be sufficient for our liquidity needs. 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$7.1 billion as ofJune 30, 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 but provides 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. 52
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As ofJune 30, 2022 , we were in compliance with all of the applicable covenants contained in the credit agreement governing our 2022 credit facility. 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 11 of the consolidated financial statements included in this Quarterly Report for additional discussion of the covenant requirements of our 2022 credit facility. As ofJune 30, 2022 , we had$406 million of borrowings on our 2022 credit facility and$109 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 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 ofJune 30, 2022 , we had borrowings under the Term Loan of$547 million .
Other key financing activities over the last six 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 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$13 million of our Term Loan principal. •InMarch 2022 , we repurchased$15 million of our 7.75% Senior Notes due 2027 and$5 million of our 8.375% Senior Notes due 2028, resulting in a$2 million loss on debt extinguishment. •InApril 2022 , we repurchased$4 million of our 7.75% Senior Notes due 2027 and$23 million of our 8.375% Senior Notes due 2028, resulting in a$3 million loss on debt extinguishment.
•In
As ofAugust 2, 2022 , we had long-term debt issuer ratings of Ba1 by Moody's (rating upgraded and stable outlook affirmed onMay 31, 2022 ), 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 inJanuary 2022 , the interest rate for our 4.95% senior notes dueJanuary 2025 ("2025 Notes") was 5.95%, reflecting a net downgrade in our bond ratings since their issuance. OnMay 31, 2022 , Moody's upgraded our bond rating to Ba1, which will decrease the interest rate on the 2025 Notes from 5.95% to 5.70% for coupon payments paid afterJuly 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.
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