# RANGE RESOURCES CORP (RRC) FY 2021 MD&A

Verbatim Item 7 Management's Discussion and Analysis from RANGE RESOURCES CORP's 10-K for fiscal year 2021.

SEC filing source: https://www.sec.gov/Archives/edgar/data/315852/000095017022001634/rrc-20211231.htm
Accession: 0000950170-22-001634
Filing date: 2022-02-22
Report date: 2021-12-31
Extracted structurally from real Item 7 body heading to real Item 7A/8 boundary.
Confidence: high

Company profile: /company/RRC/
All MD&A years: /company/RRC/mda/
Next year: /company/RRC/mda/fy2022/ (FY 2022)

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion is intended to assist you in understanding our business and results of operations together with our present financial condition and should be read in conjunction with the information under Item 8. Financial Statements and Supplementary Data and other financial information found elsewhere in this Form 10-K. See also matters referenced in the foregoing pages under “Disclosures Regarding Forward-Looking Statements.”

The following tables and discussions set forth key operating and financial data for the years ended December 31, 2021 and 2020. For similar discussions of the year ended December 31, 2020 compared to December 31, 2019 results, refer to Item 7. “Managements’ Discussion and Analysis of Financial Condition and Results of Operations” under Part II of our annual report on Form 10-K for the year ended December 31, 2020, which was filed with the SEC on February 23, 2021.

Overview of Our Business

We are an independent natural gas, natural gas liquids (“NGLs,”) crude oil and condensate company engaged in the exploration, development and acquisition of natural gas and crude oil properties located in the Appalachian region of the United States. We operate in one segment and have a single company-wide management team that administers all properties as a whole rather than by discrete operating segments. We measure financial performance as a single enterprise and not on an area-by-area basis.

Our overarching business objective is to build stockholder value through returns-focused development of natural gas properties. Our strategy to achieve our business objective is to generate consistent cash flow from reserves and production through internally generated drilling projects occasionally coupled with complementary acquisitions and divestitures of non-core or, at times, core assets. Currently, our investment portfolio is focused on high quality natural gas assets in the state of Pennsylvania. Our revenues, profitability and future growth depend substantially on prevailing prices for natural gas, NGLs, crude oil and condensate and on our ability to economically find, develop, acquire and produce natural gas, NGLs and oil reserves.

Commodity prices have been and are expected to remain volatile. We believe we are well-positioned to manage any challenges during a low commodity price environment and that we can endure the continued volatility in current and future commodity prices by:

•
exercising discipline in our capital program with the expectation of funding our capital expenditures with operating cash flows and, if required, with borrowings under our bank credit facility;

•
continuing to optimize drilling, completion and operational efficiencies;

•
remaining focused on maintaining a competitive cost structure;

•
continuing to manage price risk through the hedging of our production; and

•
continuing to manage our balance sheet.

Prices for natural gas, NGLs, crude oil and condensate fluctuate widely and affect:

•
our revenues, profitability and cash flow;

•
the quantity of natural gas, NGLs and oil that we can economically produce;

•
the quantity of natural gas, NGLs and oil shown as proved reserves;

•
the amount of cash flow available to us for capital expenditures; and

•
our ability to borrow and raise additional capital.

We prepare our financial statements in conformity with U.S. GAAP, which require us to make estimates and assumptions that affect our reported results of operations and the amount of our reported assets, liabilities and proved natural gas, NGLs and oil reserves. We use the successful efforts method of accounting for our natural gas, NGLs and oil activities. Our corporate headquarters is located in Fort Worth, Texas.

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Key 2021 highlights include:

Maintained focus on our balance sheet and liquidity

•
In first quarter 2021, we issued an aggregate principal amount of $600.0 million in new 8.25% senior notes due 2029 and used the proceeds to repay a portion of the outstanding balance on our bank credit facility. We ended the year 2021 with no borrowings under our bank credit facility, $214.4 million of cash on hand and $2.1 billion available under our bank credit facility. In early January 2022, we issued an additional aggregate principal amount of $500.0 million in new 4.75% senior notes due 2030 and used those proceeds, along with cash on hand and our bank credit facility, to fully redeem our 9.25% senior notes due 2026 in early February 2022. The table below details the changes in our outstanding debt principal balances from December 31, 2020 to December 31, 2021 (in thousands):

[[GREPCENT_TABLE]]
[["","","December 31, 2020","","","Change","","","December 31, 2021"],["Bank debt","","$","702,000","","","$","(702,000",")","","$","\u2014"],["Senior notes"],["5.75% senior notes due 2021","","","25,496","","","","(25,496",")","","","\u2014"],["5.00% senior notes due 2022","","","169,589","","","","\u2014","","","","169,589"],["5.875% senior notes due 2022","","","48,528","","","","\u2014","","","","48,528"],["5.00% senior notes due 2023","","","532,335","","","","\u2014","","","","532,335"],["4.875% senior notes due 2025","","","750,000","","","","\u2014","","","","750,000"],["9.25% senior notes due 2026","","","850,000","","","","\u2014","","","","850,000"],["8.25% senior notes due 2029","","","\u2014","","","","600,000","","","","600,000"],["Other senior notes","","","490","","","","(490",")","","","\u2014"],["Total senior notes","","","2,376,438","","","","574,014","","","","2,950,452"],["Senior subordinated notes"],["5.75% senior subordinated notes due 2021","","","19,896","","","","(19,896",")","","","\u2014"],["5.00% senior subordinated notes due 2022","","","9,730","","","","(9,730",")","","","\u2014"],["5.00% senior subordinated notes due 2023","","","7,712","","","","(7,712",")","","","\u2014"],["Total senior subordinated notes","","","37,338","","","","(37,338",")","","","\u2014"],["Total debt","","","3,115,776","","","","(165,324",")","","","2,950,452"],["Cash balance (as disclosed on balance sheet)","","","(458",")","","","(213,964",")","","","(214,422",")"],["Total debt, net of cash","","$","3,115,318","","","$","(379,288",")","","$","2,736,030"]]
[[/GREPCENT_TABLE]]

•
Our banks' committed borrowing capacity remained at $2.4 billion after completing our semi-annual borrowing base redetermination in both March and September 2021;

•
In 2021, we generated $792.9 million in cash provided by operating activities, reflecting higher commodity prices which was more than sufficient to fund our capital expenditures; and

•
We ended the year with a cash balance of $214.4 million.

Financial and operational results

•
Continued to deliver our strong operational execution along with focusing on cost control that will improve our cost structure for current and future operations while emphasizing safety and protection of the environment.

•
Focused on capital efficiencies, which resulted in lower well costs and drove overall capital spending $10.6 million lower than the original budget for the year;

•
Improved our drilling and completion costs per foot compared to 2020; and

•
Increased proved reserves to 17.8 Tcfe, 3% higher than 2020.

Continued to focus on safe, responsible and sustainable operations

•
Expanded our goal of net zero GHG emissions by 2025 to include Scope 1 and Scope 2 emissions;

•
Committed to a pilot program to certify our responsibly sourced natural gas;

•
Continued to recycle approximately 100% of produced water; and

•
Continued quarterly leak detection inspections.

38

Management’s Discussion and Analysis of Results of Operations

Commodity prices have remained volatile. Benchmarks for natural gas, oil and NGLs increased in 2021 compared to 2020. As a result, we experienced significant increases in our price realizations when compared to the same period of 2020. We had many operational, financial and strategic successes in 2021 as we continued to focus on enhancing margins and returns, driving operational efficiencies and maintaining liquidity. We believe we have positioned ourselves for long-term success through the commodity price cycles.

Overview of 2021 Results

For the year ended December 31, 2021, we experienced an increase in revenue from the sale of natural gas, NGLs and oil due to a 86% increase in net realized prices (average prices including all derivative settlements and third-party transportation costs paid by us) partially offset by 5% lower production volumes when compared to 2020. Daily production in 2021 averaged 2.1 Bcfe compared to 2.2 Bcfe in 2020 reflecting the impact of the sale of our North Louisiana properties. Average natural gas differentials were below NYMEX but slightly improved from the prior year. Direct operating costs were lower when compared to the same period of 2020.

During 2021, we recognized net income of $411.8 million, or $1.61 per diluted common share compared to net loss of $711.8 million, or $2.95 per diluted common share during 2020. The improvement in net income for the year ended December 31, 2021 when compared to 2020 is due to significantly higher realized prices, lower proved property impairment charges and lower divestiture contract obligation expenses, which in the prior year were related to the sale of our North Louisiana assets, partially offset by lower gain on sale of assets and higher deferred compensation plan expenses.

During 2021, our financial and operating performance included the following results:

•
reduced total debt $165.3 million and increased cash on hand $214.0 million;

•
increased cash flow from operating activities by 195% from the same period of 2020;

•
spent $10.6 million less than our initial 2021 capital budget of $425.0 million;

•
drilled 58.1 net wells with a 100% success rate;

•
continued development of our Marcellus Shale inventory by maintaining production, proving up acreage and acquiring additional unproved acreage;

•
increased revenue from the sale of natural gas, NGLs and oil by100% from the same period of 2020 with a 110% increase in average realized prices (before cash settlements on our derivatives) partially offset by slightly lower production volumes;

•
increased revenue from the sale of natural gas, NGLs and oil (including settlements on our derivatives) by 38% from the same period of 2020;

•
reduced direct operating expense per mcfe 9% from 2020;

•
increased general and administrative expenses per mcfe by 10% from 2020 due to higher legal expenses and settlements;

•
reduced our DD&A rate per mcfe 2% from 2020;

•
issued $600.0 million of new senior notes and used the proceeds to reduce borrowings under our bank credit facility;

•
entered into additional commodity-based derivative contracts for 2022 through 2024; and

•
ended the year with cash on hand of $214.4 million and stockholders’ equity of $2.1 billion.

We generated $792.9 million of cash flow from operating activities in 2021, an increase of $524.3 million from 2020 which reflects significantly higher realized prices and lower net operating costs somewhat offset by higher comparative working capital outflows ($241.7 million outflow during 2021 compared to $53.9 million outflow in 2020) due to higher commodity prices. We ended 2021 with $2.1 billion of available committed borrowing capacity.

Acquisitions

During 2021, we spent $22.0 million to acquire unproved acreage compared to $26.2 million in 2020. We continue selective acreage leasing and lease renewals to consolidate our acreage positions in the Marcellus Shale play in Pennsylvania.

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Divestitures

Our gain (loss) on sale of assets is primarily attributable to the following divestitures (in thousands):

[[GREPCENT_TABLE]]
[["Asset Sold","","Completion Date","","Gain (Loss) on Sale of Assets"],["Year Ended December 31, 2021:"],["North Louisiana assets","","August 2020","","$","479"],["Other","","Various","","$","222"],["Year Ended December 31, 2020:"],["North Louisiana assets","","August 2020","","$","(9,503",")"],["Shallow legacy assets in Northwest Pennsylvania","","March 2020","","$","122,506"],["Other","","Various","","$","(2,212",")"]]
[[/GREPCENT_TABLE]]

2022 Outlook

As we enter 2022, we believe we are positioned for sustainable long-term success. For 2022, we expect our capital budget to be in the range of $460.0 million to $480.0 million for natural gas, NGLs, crude oil and condensate related activities, excluding proved property acquisitions, for which we do not budget. As has been our historical practice, we will periodically review our capital expenditures throughout the year and may adjust the budget based on commodity prices, drilling success and other factors. We expect our 2022 capital budget to achieve production similar to our 2021 production. Our 2022 capital budget is designed to focus on continuing to improve corporate returns and generating free cash flow. To the extent commodity prices decline, we may reduce the capital budget with the intent of limiting capital spending to at or below cash flow. The prices we receive for our natural gas, NGLs and oil production are largely based on current market prices, which are beyond our control. The price risk on a portion of our forecasted natural gas, NGLs and oil production for 2022 is partially mitigated by entering into commodity derivative contracts and we intend to continue to enter into these types of contracts. We believe it is likely that commodity prices will continue to be volatile during 2022.

Market Conditions

Prices for natural gas, NGLs and oil that we produce significantly impact our revenues and cash flows. Natural gas, NGLs and oil benchmarks increased in 2021 when compared to the same period of 2020 and, as a result, we experienced a significant increase in price realizations. As we continue to monitor the impact of the actions of OPEC and other large producing nations, global inventories of oil and gas and the uncertainty associated with recovering oil demand, future monetary policy and governmental policies aimed at redirecting fossil fuel consumption towards lower carbon energy, we expect prices for some or all of the commodities we produce to remain volatile. NYMEX natural gas futures have shown strong improvements based on market expectations that associated gas related activity in oil basins and dry gas basin activity, will show modest rates of growth compared with the past due to capital discipline and core inventory exhaustion. In addition, the global energy crisis further highlighted the low cost and low emissions shale gas resource base in North America, supporting continued strong structural demand growth for U.S. LNG exports and domestic industrial gas demand. Other factors such as the duration of the COVID-19 pandemic and the speed and effectiveness of vaccine distributions or other medical advances to combat the virus may impact the recovery of world economic growth and the demand for oil, natural gas and NGLs.

Prices for various quantities of natural gas, NGLs and oil that we produce significantly impact our revenues and cash flows. Prices for commodities, such as hydrocarbons, are inherently volatile. Recently, natural gas prices have increased, when compared to December 2021, with the average NYMEX monthly settlement price for natural gas increasing to $6.27 per mcf for February 2022 with the recent colder weather and a decline in natural gas storage inventories. Crude oil prices have also increased, when compared to December 2021, to $82.98 per barrel in January 2022. The following table lists related benchmarks for natural gas, oil and NGLs composite prices for the years ended December 31, 2021 and 2020.

[[GREPCENT_TABLE]]
[["","","Year Ended December 31,"],["","","2021","","","2020"],["Benchmarks:"],["Average NYMEX prices (a)"],["Natural gas (per mcf)","","$","3.88","","","$","2.06"],["Oil (per bbl)","","$","67.93","","","$","39.66"],["Mont Belvieu NGLs composite (per gallon) (b)","","$","0.74","","","$","0.37"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["(a)","Based on average of bid week prompt month prices on the New York Mercantile Exchange (\u201cNYMEX\u201d)."],["(b)","Based on our estimated NGLs product composition per barrel."]]
[[/GREPCENT_TABLE]]

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Our price realizations (not including the impact of our derivatives) may differ from the benchmarks for many reasons, including quality, location, or production being sold at different indices.

Natural Gas, NGLs and Oil Sales, Production and Realized Price Calculations

Our revenues vary from year to year as a result of changes in realized commodity prices and production volumes. In 2021, natural gas, NGLs and oil sales increased 100% from 2020 with a 5% decrease in production and a 110% increase in realized prices (excluding cash settlements on our derivatives). The following table illustrates the primary components of natural gas, NGLs, crude oil and condensate sales for the last two years (in thousands):

[[GREPCENT_TABLE]]
[["","","Year Ended December 31,"],["","","2021","","","2020","","","Change","","","% Change"],["Natural gas, NGLs and Oil sales"],["Natural gas","","$","1,896,231","","","$","943,740","","","$","952,491","","","","101","%"],["NGLs","","","1,135,826","","","","578,454","","","","557,372","","","","96","%"],["Oil and condensate","","","182,970","","","","85,519","","","","97,451","","","","114","%"],["Total natural gas, NGLs and oil sales","","$","3,215,027","","","$","1,607,713","","","$","1,607,314","","","","100","%"]]
[[/GREPCENT_TABLE]]

Production is maintained through drilling success as we place new wells on production which is partially offset by the natural decline of our natural gas and oil reserves through production and asset sales. For 2021, our production decreased 5% reflecting the impact of the sale of our North Louisiana properties. Production from our North Louisiana properties was 38.0 Bcfe in 2020 with the sale of these properties closing in August 2020. Our production for the last two years is set forth in the following table:

[[GREPCENT_TABLE]]
[["","","Year Ended December 31,"],["","","2021","","","2020","","","Change","","","% Change"],["Production (a)"],["Natural gas (mcf)","","","541,021,442","","","","574,529,290","","","","(33,507,848",")","","","(6","%)"],["NGLs (bbls)","","","36,372,862","","","","37,491,546","","","","(1,118,684",")","","","(3","%)"],["Crude oil and condensate (bbls)","","","3,044,026","","","","2,829,495","","","","214,531","","","","8","%"],["Total (mcfe) (b)","","","777,522,772","","","","816,455,536","","","","(38,932,764",")","","","(5","%)"],["Average daily production (a)"],["Natural gas (mcf)","","","1,482,251","","","","1,569,752","","","","(87,501",")","","","(6","%)"],["NGLs (bbls)","","","99,652","","","","102,436","","","","(2,784",")","","","(3","%)"],["Crude oil and condensate (bbls)","","","8,340","","","","7,731","","","","609","","","","8","%"],["Total (mcfe) (b)","","","2,130,199","","","","2,230,753","","","","(100,554",")","","","(5","%)"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["(a)","Represents volumes sold regardless of when produced."],["(b)","Oil and NGLs volumes are converted to mcfe at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil and natural gas, which is not indicative of the relationship between oil and natural gas prices."]]
[[/GREPCENT_TABLE]]

41

Our average realized price (including all derivative settlements and third-party transportation costs paid by Range) received during 2021 was $1.92 per mcfe compared to $1.03 per mcfe in 2020. Because we record transportation costs on two separate bases, as required by U.S. GAAP, we believe computed final realized prices should include the impact of transportation, gathering, processing and compression expense. Average sales prices (excluding derivative settlements) do not include any derivative settlements or third-party transportation costs which are reported in transportation, gathering and compression expense on the accompanying consolidated statements of operations. Average sales prices (excluding derivative settlements) do include transportation costs where we receive net proceeds from the purchaser. Our average realized price (including all derivative settlements and third-party transportation costs paid by Range) calculation includes all cash settlements for derivatives. Our derivative settlements included in our realized price calculations do not include settlements of contingent consideration related to the sale of our North Louisiana properties. Average realized price calculations for the last two years are shown below:

[[GREPCENT_TABLE]]
[["","","Year Ended December 31,"],["","","2021","","","2020","","","Change","","","% Change"],["Average Prices"],["Average sales prices (excluding derivative settlements):"],["Natural gas (per mcf)","","$","3.50","","","$","1.64","","","$","1.86","","","","113","%"],["NGLs (per bbl)","","","31.23","","","","15.43","","","","15.80","","","","102","%"],["Crude oil (per bbl)","","","60.11","","","","30.22","","","","29.89","","","","99","%"],["Total (per mcfe) (a)","","","4.13","","","","1.97","","","","2.16","","","","110","%"],["Average realized prices (including all derivative settlements):"],["Natural gas (per mcf)","","$","2.74","","","$","2.09","","","$","0.65","","","","31","%"],["NGLs (per bbl)","","","28.70","","","","15.73","","","","12.97","","","","82","%"],["Crude oil (per bbl)","","","46.16","","","","48.79","","","","(2.63",")","","","(5","%)"],["Total (per mcfe) (a)","","","3.43","","","","2.36","","","","1.07","","","","45","%"],["Average realized prices (including all derivative settlements and third-party transportation costs paid by Range):"],["Natural gas (per mcf)","","$","1.51","","","$","0.96","","","$","0.55","","","","57","%"],["NGLs (per bbl)","","","14.64","","","","4.06","","","","10.58","","","","260","%"],["Crude oil (per bbl)","","","45.86","","","","48.46","","","","(2.60",")","","","(5","%)"],["Total (per mcfe) (a)","","","1.92","","","","1.03","","","","0.89","","","","86","%"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["(a)","Oil and NGLs volumes are converted at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil to natural gas, which is not indicative of the relationship between oil and natural gas prices."]]
[[/GREPCENT_TABLE]]

Realized prices include the impact of basis differentials and gains or losses realized from our basis hedging. The prices we receive for our natural gas can be more or less than the NYMEX price because of adjustments for delivery location, relative quality and other factors. The following table provides this impact on a per mcf basis:

[[GREPCENT_TABLE]]
[["","","Year Ended December 31,"],["","","2021","","","2020"],["Average natural gas differentials below NYMEX","","$","(0.38",")","","$","(0.42",")"],["Realized gains on basis hedging","","$","0.04","","","$","0.06"]]
[[/GREPCENT_TABLE]]

The following tables reflect our production and average realized commodity prices (excluding derivative settlements and third-party transportation costs paid by Range) (in thousands, except prices):

[[GREPCENT_TABLE]]
[["","","Year Ended December 31,"],["","","2020","","","Price Variance","","","Volume Variance","","","2021"],["Natural gas"],["Price (per mcf)","","$","1.64","","","$","1.86","","","$","\u2014","","","$","3.50"],["Production (Mmcf)","","","574,529","","","","\u2014","","","","(33,508",")","","","541,021"],["Natural gas sales","","$","943,740","","","$","1,007,532","","","$","(55,041",")","","$","1,896,231"]]
[[/GREPCENT_TABLE]]

42

[[GREPCENT_TABLE]]
[["","","Year Ended December 31,"],["","","2020","","","Price Variance","","","Volume Variance","","","2021"],["NGLs"],["Price (per bbl)","","$","15.43","","","$","15.80","","","$","\u2014","","","$","31.23"],["Production (Mbbls)","","","37,492","","","","\u2014","","","","(1,119",")","","","36,373"],["NGLs sales","","$","578,454","","","$","574,632","","","$","(17,260",")","","$","1,135,826"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["","","Year Ended December 31,"],["","","2020","","","Price Variance","","","Volume Variance","","","2021"],["Crude oil"],["Price (per bbl)","","$","30.22","","","$","29.89","","","$","\u2014","","","$","60.11"],["Production (Mbbls)","","","2,829","","","","\u2014","","","","215","","","","3,044"],["Crude oil sales","","$","85,519","","","$","90,967","","","$","6,484","","","$","182,970"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["","","Year Ended December 31,"],["","","2020","","","Price Variance","","","Volume Variance","","","2021"],["Consolidated"],["Price (per mcfe)","","$","1.97","","","$","2.16","","","$","\u2014","","","$","4.13"],["Production (Mmcfe)","","","816,456","","","","\u2014","","","","(38,933",")","","","777,523"],["Total natural gas, NGLs and oil sales","","$","1,607,713","","","$","1,683,977","","","$","(76,663",")","","$","3,215,027"]]
[[/GREPCENT_TABLE]]

Transportation, gathering, processing and compression expense was $1.2 billion in 2021 compared to $1.1 billion in 2020. These third-party costs are higher due to the impact of higher NGLs prices which result in higher processing costs and higher fuel costs somewhat offset by the sale of our North Louisiana assets in third quarter 2020 and transportation capacity released in Pennsylvania in 2020. We have included these costs in the calculation of average realized prices (including all derivative settlements and third-party transportation expenses paid by Range). The following table summarizes transportation, gathering, processing and compression expense for the last two years (in thousands) and on a per mcf and per barrel basis:

[[GREPCENT_TABLE]]
[["","","Year Ended December 31,"],["","","2021","","","2020","","","Change","","","% Change"],["Natural gas","","$","661,990","","","$","650,071","","","$","11,919","","","","2","%"],["NGLs","","","511,568","","","","437,474","","","","74,094","","","","17","%"],["Oil","","","911","","","","945","","","","(34",")","","","(4","%)"],["Total","","$","1,174,469","","","$","1,088,490","","","$","85,979","","","","8","%"],["Natural gas (per mcf)","","$","1.22","","","$","1.13","","","$","0.09","","","","8","%"],["NGLs (per bbl)","","$","14.06","","","$","11.67","","","$","2.39","","","","20","%"],["Oil (per bbl)","","$","0.30","","","$","0.33","","","$","(0.03",")","","","(9","%)"]]
[[/GREPCENT_TABLE]]

43

Derivative fair value (loss) income was a loss of $650.2 million in 2021 compared to income of $187.7 million in 2020. All of our derivatives are accounted for using the mark-to-market accounting method. Mark-to-market accounting treatment creates volatility in our revenues as unrealized gains and losses from derivatives are included in total revenues. As commodity prices increase or decrease, such changes will have an opposite effect on the mark-to-market value of our derivatives. Gains on our derivatives generally indicate lower wellhead revenues in the future while losses indicate higher future wellhead revenues. At December 31, 2021, our commodity derivative contracts were recorded at their fair value, which was a net derivative liability of $169.5 million, an increase of $151.5 million from the $18.0 million net derivative liability recorded as of December 31, 2020. We have also entered into basis swap agreements to limit volatility caused by changing differentials between NYMEX and regional prices received. These basis swaps are marked to market and we recognized a net derivative asset of $16.0 million as of December 31, 2021 compared to a net derivative asset of $3.7 million as of December 31, 2020. As of December 31, 2021, we have propane basis swaps to limit the volatility caused by changing differentials between Mont Belvieu and international propane indexes which are recognized as a net derivative asset of $123,000 as of December 31, 2021 compared to a net derivative asset of $794,000 as of December 31, 2020. In connection with our international propane swaps, we also have freight swap contracts which lock in the freight rate for a specific trade route on the Baltic Exchange which are recognized as a net derivative asset of $114,000 as of December 31, 2021 compared to a net derivative asset of $1.1 million as of December 31, 2020. The following table summarizes the impact of our commodity derivatives for the last two years (in thousands):

[[GREPCENT_TABLE]]
[["","","Year Ended December 31,"],["","","2021","","","2020"],["Derivative fair value (loss) income per consolidated statements of operations","","$","(650,216",")","","$","187,711"],["Non-cash fair value (loss) gain: (1)"],["Natural gas derivatives","","$","(130,114",")","","$","(132,978",")"],["Oil derivatives","","","(23,879",")","","","519"],["NGLs derivatives","","","14,100","","","","(3,004",")"],["Freight derivatives","","","(990",")","","","(425",")"],["Contingent consideration","","","10,680","","","","970"],["Total non-cash fair value loss (1)","","$","(130,203",")","","$","(134,918",")"],["Net cash (payment) receipt on derivative settlements:"],["Natural gas derivatives","","$","(415,228",")","","$","258,797"],["Oil derivatives","","","(42,447",")","","","52,544"],["NGLs derivatives","","","(91,838",")","","","11,288"],["Contingent consideration","","","29,500","","","","\u2014"],["Total net cash (payment) receipt","","$","(520,013",")","","$","322,629"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["(1)","Non-cash fair value adjustments on commodity derivatives is a non-GAAP measure. Non-cash fair value adjustments on commodity derivatives only represent the net change between periods of the fair market values of commodity derivative positions and exclude the impact of settlements on commodity derivatives during the period. We believe that non-cash fair value adjustments on commodity derivatives is a useful supplemental disclosure to differentiate non-cash fair market value adjustments from settlements on commodity derivatives during the period. Non-cash fair value adjustments on commodity derivatives is not a measure of financial or operating performance under GAAP, nor should it be considered a substitute for derivative fair value income or loss as reported in our consolidated statements of operations."]]
[[/GREPCENT_TABLE]]

Brokered natural gas, marketing and other revenue was $365.4 million in 2021 compared to $173.3 million in 2020. We enter into purchase transactions with third parties and separate sale transactions with third parties at different times to utilize available pipeline capacity and to fulfill sales commitments in the event of operational upsets. The 2021 period includes $342.4 million of revenue from the sale of natural gas that is not related to our production (brokered) and $6.9 million of revenue from the sale of NGLs that is not related to our production. The 2020 period includes $160.1 million of revenue from the brokered sale of natural gas and $3.8 million of revenue from the sale of NGLs that is not related to our production. These revenues increased compared to 2020 due to higher brokered volumes and higher sales prices. The twelve months ended December 31, 2021 also includes $8.8 million received as part of a capacity release agreement.

44

Costs and Expenses per mcfe

We believe some of our expense fluctuations are best analyzed on a unit-of-production, or per mcfe, basis. The following presents information about certain of our expenses on a per mcfe basis for the last two years:

[[GREPCENT_TABLE]]
[["","","Year Ended December 31,"],["","","2021","","","2020","","","Change","","","% Change"],["Direct operating expense","","$","0.10","","","$","0.11","","","$","(0.01",")","","","(9","%)"],["Production and ad valorem tax expense","","","0.04","","","","0.03","","","","0.01","","","","33","%"],["General and administrative expense","","","0.22","","","","0.20","","","","0.02","","","","10","%"],["Interest expense","","","0.29","","","","0.24","","","","0.05","","","","21","%"],["Depletion, depreciation and amortization expense","","","0.47","","","","0.48","","","","(0.01",")","","","(2","%)"]]
[[/GREPCENT_TABLE]]

Direct operating expense was $75.3 million in 2021 compared to $92.2 million in 2020. Direct operating expenses include normally recurring expenses to operate and produce our wells, non-recurring workovers and repair-related expenses. On an absolute basis, our direct operating expenses for 2021 decreased 18% from the prior year primarily due to the impact of the sale of our higher cost North Louisiana assets in third quarter 2020 and lower workover costs. We incurred $3.4 million of workover costs in 2021 compared to $7.3 million of workover costs in 2020.

On a per mcfe basis, operating expense for 2021 decreased $0.01, or 9% from the same period of 2020, with the decrease due to lower workover costs. Stock-based compensation expense represents the amortization of equity grants as part of the compensation of field employees. The following table summarizes direct operating expenses per mcfe for the last two years:

[[GREPCENT_TABLE]]
[["","","Year Ended December 31,"],["","","2021","","","2020","","","Change","","","% Change"],["Lease operating expense","","$","0.10","","","$","0.10","","","$","\u2014","","","","\u2014","%"],["Workovers","","","\u2014","","","","0.01","","","","(0.01",")","","","(100","%)"],["Stock-based compensation","","","\u2014","","","","\u2014","","","","\u2014","","","","\u2014","%"],["Total direct operating expense","","$","0.10","","","$","0.11","","","$","(0.01",")","","","(9","%)"]]
[[/GREPCENT_TABLE]]

Production and ad valorem taxes are paid based on market prices, not hedged prices. This expense category also includes the Pennsylvania impact fee. In 2012, Pennsylvania enacted an “impact fee” on unconventional natural gas and oil production which includes the Marcellus Shale. The impact fee is based upon the year wells are drilled and the fee varies, like a severance tax, based upon natural gas prices. The year ended December 31, 2021 includes a $29.3 million impact fee compared to $17.7 million in the year ended December 31, 2020 with the increase primarily due to higher natural gas prices. Production and ad valorem taxes (excluding the impact fee) were less than $50,000 in 2021 compared to $7.0 million in 2020 with the decline due to the sale of our North Louisiana assets in third quarter 2020. The following table summarizes production and ad valorem taxes per mcfe for the last two years:

[[GREPCENT_TABLE]]
[["","","Year Ended December 31,"],["","","2021","","","2020","","","Change","","","% Change"],["Production taxes","","$","\u2014","","","$","0.01","","","$","(0.01",")","","","(100","%)"],["Ad valorem taxes","","","\u2014","","","","\u2014","","","","\u2014","","","","\u2014","%"],["Impact fee","","","0.04","","","","0.02","","","","0.02","","","","100","%"],["Total production and ad valorem","","$","0.04","","","$","0.03","","","$","0.01","","","","33","%"]]
[[/GREPCENT_TABLE]]

45

General and administrative expense was $169.8 million for 2021 compared to $159.4 million for 2020. The increase in 2021, when compared to 2020, is primarily due to higher legal expenses and legal settlements of $7.7 million and higher stock-based compensation partially offset by lower salaries and benefits and lower technology costs. As of December 31, 2021, the number of general and administrative employees decreased 2% when compared to December 31, 2020.

On a per mcfe basis, general and administrative expense for 2021 increased 10% from the same period of 2020, with the increase due to higher legal expenses and legal settlements and higher stock-based compensation partially offset by lower salaries and benefits. Stock-based compensation expense represents the amortization of stock-based compensation awards granted to our employees and our non-employee directors as part of their compensation. The following table summarizes general and administrative expenses per mcfe for the last two years:

[[GREPCENT_TABLE]]
[["","","Year Ended December 31,"],["","","2021","","","2020","","","Change","","","% Change"],["General and administrative","","$","0.17","","","$","0.16","","","$","0.01","","","","6","%"],["Stock-based compensation","","","0.05","","","","0.04","","","","0.01","","","","25","%"],["Total general and administrative expense","","$","0.22","","","$","0.20","","","$","0.02","","","","10","%"]]
[[/GREPCENT_TABLE]]

Interest expense was $227.3 million for 2021 compared to $192.7 million for 2020. The following table presents information about interest expense per mcfe for the last two years:

[[GREPCENT_TABLE]]
[["","","Year Ended December 31,"],["","","2021","","","2020","","","Change","","","% Change"],["Bank credit facility","","$","0.02","","","$","0.03","","","$","(0.01",")","","","(33","%)"],["Senior notes","","","0.26","","","","0.20","","","","0.06","","","","30","%"],["Amortization of deferred financing costs and other","","","0.01","","","","0.01","","","","\u2014","","","","\u2014","%"],["Total interest expense","","$","0.29","","","$","0.24","","","$","0.05","","","","21","%"],["Average debt outstanding (in thousands)","","$","3,100,067","","","$","3,239,867","","","$","(139,800",")","","","(4","%)"],["Average interest rate (a)","","","7.0","%","","","5.7","%","","","1.3","%","","","23","%"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["(a)","Includes commitment fees but excludes amortization of debt issue costs and amortization of discount."]]
[[/GREPCENT_TABLE]]

On an absolute basis, the increase in interest expense for 2021 from the same period of 2020 was primarily due to higher average interest rates partially offset by slightly lower outstanding debt balances. See Note 7 to our consolidated financial statements for additional information. Average debt outstanding on the bank credit facility for 2021 was $144.9 million compared to $656.7 million for 2020 and the weighted average interest rate on the bank credit facility was 2.1% for 2021 compared to 2.6% in 2020.

Depletion, depreciation and amortization (“DD&A”) was $364.6 million in 2021 compared to $394.3 million in 2020. The decrease in 2021 when compared to 2020 is due to a 2% decrease in depletion rates and a 5% decrease in production volumes.

On a per mcfe basis, DD&A decreased to $0.47 in 2021 compared to $0.48 in 2020. Depletion expense, the largest component of DD&A, was $0.46 per mcfe in 2021 compared to $0.47 per mcfe in 2020. We have historically adjusted our depletion rates in the fourth quarter of each year based on our year-end reserve report and at other times during the year when circumstances indicate there has been a significant change in reserves or costs. We currently expect our DD&A rate to be approximately $0.46 per mcfe in 2022, based on our current production estimates. In areas where we are actively drilling, our fourth quarter adjusted 2021 depletion rates were slightly lower than fourth quarter 2020. The decrease in DD&A per mcfe in 2021 when compared to 2020 is due to the mix of our production from our properties with lower depletion rates and asset sales. The following table summarizes DD&A expenses per mcfe for the last two years:

[[GREPCENT_TABLE]]
[["","","Year Ended December 31,"],["","","2021","","","2020","","","Change","","","% Change"],["Depletion and amortization","","$","0.46","","","$","0.47","","","$","(0.01",")","","","(2","%)"],["Depreciation","","","\u2014","","","","\u2014","","","","\u2014","","","","\u2014","%"],["Accretion and other","","","0.01","","","","0.01","","","","\u2014","","","","\u2014","%"],["Total DD&A expenses","","$","0.47","","","$","0.48","","","$","(0.01",")","","","(2","%)"]]
[[/GREPCENT_TABLE]]

46

Other Operating Expenses

Our total operating expenses also include other expenses that generally do not trend with production. These expenses include stock-based compensation, brokered natural gas and marketing, exploration expense, abandonment and impairment of unproved properties, exit and termination costs, deferred compensation plan, loss (gain) on early extinguishment of debt and impairment of proved properties and other assets. The following table details stock-based compensation that is allocated to functional expense categories for the last two years (in thousands):

[[GREPCENT_TABLE]]
[["","","2021","","","2020"],["Direct operating expense","","$","1,310","","","$","1,078"],["Brokered natural gas and marketing expense","","","1,794","","","","1,416"],["Exploration expense","","","1,507","","","","1,279"],["General and administrative expense","","","39,673","","","","32,905"],["Termination costs","","","\u2014","","","","2,165"],["Total stock-based compensation","","$","44,284","","","$","38,843"]]
[[/GREPCENT_TABLE]]

Stock-based compensation includes the amortization of restricted stock and PSUs grants.

Brokered natural gas and marketing expense was $367.3 million in 2021 compared to $188.3 million in 2020. We enter into purchase transactions with third parties and separate sale transactions with third parties at different times to utilize available pipeline capacity and fulfill sales commitments in the event of operational upsets. The increase in these costs reflects higher broker purchase volumes and higher purchase prices. The following table details our brokered natural gas, marketing and other net margin which includes the net effect of these third-party transactions for the two-year period ended December 31, 2021 (in thousands):

[[GREPCENT_TABLE]]
[["","","2021","","","2020"],["Brokered natural gas sales","","$","342,431","","","$","160,122"],["Brokered NGLs sales","","","6,925","","","","3,776"],["Other marketing revenue","","","16,056","","","","9,375"],["Brokered natural gas purchases and transportation","","","(350,426",")","","","(175,039",")"],["Brokered NGLs purchases","","","(8,044",")","","","(4,691",")"],["Other marketing expense","","","(8,818",")","","","(8,586",")"],["Net brokered natural gas and marketing net margin","","$","(1,876",")","","$","(15,043",")"]]
[[/GREPCENT_TABLE]]

Exploration expense was $23.6 million in 2021 compared to $32.7 million in 2020. Exploration expense in 2021 was lower compared to the prior year due to lower delay rentals and other costs, lower personnel costs and lower seismic expenses. Stock-based compensation represents the amortization of equity stock grants as part of the compensation of our exploration staff. The following table details our exploration related expenses for the last two years (in thousands):

[[GREPCENT_TABLE]]
[["","","Year Ended December 31,"],["","","2021","","","2020","","","Change","","","% Change"],["Seismic","","$","129","","","$","1,761","","","$","(1,632",")","","","(93","%)"],["Delay rentals and other","","","16,597","","","","21,187","","","$","(4,590",")","","","(22","%)"],["Personnel expense","","","5,322","","","","7,539","","","$","(2,217",")","","","(29","%)"],["Stock-based compensation expense","","","1,507","","","","1,279","","","$","228","","","","18","%"],["Exploratory dry hole expense","","","\u2014","","","","888","","","$","(888",")","","","(100","%)"],["Total exploration expense","","$","23,555","","","$","32,654","","","$","(9,099",")","","","(28","%)"]]
[[/GREPCENT_TABLE]]

Abandonment and impairment of unproved properties was $7.2 million in 2021 compared to $19.3 million in 2020. These costs declined when compared to the same period of 2020 due to lower estimated lease expirations in Pennsylvania. Impairment of individually insignificant unproved properties is assessed and amortized on an aggregate basis based on our average holding period, expected forfeiture rate and anticipated drilling success. We assess individually significant unproved properties for impairment on a quarterly basis and recognize a loss where circumstances indicate impairment in value. In determining whether a significant unproved property is impaired we consider numerous factors including, but not limited to, current exploration plans, favorable or unfavorable activity on the property being evaluated and/or adjacent properties, our geologists’ evaluation of the property and the remaining months in the lease term for the property. In certain circumstances, our future plans to develop acreage may accelerate our impairment.

47

Exit and termination costs in 2021 were $21.7 million compared to $547.4 million in 2020. In August 2020, we completed the sale of our North Louisiana operations in a transaction that included the retention of certain related gathering, transportation and processing obligations extending until 2030. The present value of these estimated future obligations totaled $479.8 million which was recorded in third quarter 2020. In addition, we agreed to pay a midstream company $28.5 million to reduce our financial obligation related to the minimum volume commitments associated with this asset. In second quarter 2020, we also negotiated capacity releases on certain transportation pipelines in Pennsylvania and we recorded $10.4 million of exit costs which represents the discounted present volume of our remaining obligations. In the twelve months ended December 31, 2021, we recorded $48.7 million accretion expense related to retained liabilities and in second quarter 2021, we recorded a gain of $28.2 million to reduce our original estimate of these retained obligations due to payments being lower than our forecast and a change in our forecasted drilling plans of the buyer. The following table details our exit and termination costs for the last two years (in thousands):

[[GREPCENT_TABLE]]
[["","","Year Ended December 31,"],["","","2021","","","2020"],["Severance costs","","$","567","","","$","5,909"],["Transportation contract capacity releases (including accretion of discount)","","","754","","","","10,900"],["Divestiture contract obligation (including accretion of discount)","","","20,340","","","","499,935"],["One-time minimum volume commitment contract payment","","","\u2014","","","","28,500"],["Stock-based compensation","","","\u2014","","","","2,165"],["","","$","21,661","","","$","547,409"]]
[[/GREPCENT_TABLE]]

Deferred compensation plan expense was a loss of $68.4 million in 2021 compared to a loss of $12.5 million in 2020. Our stock price increased to $17.83 at December 31, 2021 from $6.70 at December 31, 2020. This non-cash item relates to the increase or decrease in value of the liability associated with our common stock that is vested and held in our deferred compensation plan. The deferred compensation liability is adjusted to fair value by a charge or a credit to deferred compensation plan expense. Common shares are placed in the deferred compensation plan when granted to eligible participants.

Loss (gain) on early extinguishment of debt was a loss of $98,000 in 2021 compared to a gain of $14.1 million in 2020. In 2020, we purchased for cash a total of $1.0 billion aggregate principal amount of various senior and senior subordinated notes. An early cash tender of $20.4 million was paid to note holders who tendered their notes within the ten business day offer period. We recorded a loss on early extinguishment of debt of $25.5 million, net of transaction call premium costs and the expensing of the remaining deferred financing costs on the repurchased debt. Also in 2020, we purchased in the open market $161.0 million principal amount of various senior and senior subordinated notes. We recorded a gain on early extinguishment of debt of $39.6 million, net of transaction costs and the expensing of the remaining deferred financing costs.

Impairment of proved properties and other was $79.0 million in 2020. There were no proved property impairments in 2021. We assess our long-lived assets whenever events or circumstances indicate the carrying value may not be recoverable. Fair value is generally determined using an income approach based on internal estimates of future production levels, prices, drilling and operating costs and discount rates. In some cases, we may also use a market approach, based on either anticipated sales proceeds less costs to sell or a market comparable sales price. In fourth quarter 2019, we recorded impairment expense related to our North Louisiana assets due to a shift in business strategy employed by management and the possibility of a divestiture of these assets. Early in 2020, we recognized additional impairment charges of $77.0 million related to these North Louisiana assets that reduced the carrying value to the anticipated sales proceeds which is a market approach. See Note 10 to our consolidated financial statements for additional details.

48

Income tax (benefit) expense was a benefit of $9.7 million in 2021 compared to a benefit of $25.6 million in 2020. The 2021 decline in the income tax benefit reflects a $1.1 billion improvement in our operating income before income taxes when compared to 2020 offset by changes in our valuation allowances due to the current commodity price environment. The effective tax rate was (2.4%) in 2021 compared to 3.5% in 2020. Our current year effective tax rate was affected by the impact of a shift in our state apportionment factor for NGLs sales from higher state jurisdictions. The 2021 and 2020 effective tax rates were different than the statutory tax rate due to state income taxes and other discrete tax items which are detailed below. For the year ended December 31, 2021, current income tax expense relates to state income taxes. The following table summarizes our tax activity for the last two years (in thousands):

[[GREPCENT_TABLE]]
[["","","2021","","","2020"],["Total income (loss) before income taxes","","$","402,035","","","$","(737,329",")"],["U.S. federal statutory rate","","","21","%","","","21","%"],["Total tax expense (benefit) at statutory rate","","","84,427","","","","(154,839",")"],["State and local income taxes, net of federal benefit","","","16,260","","","","(38,413",")"],["State rate and law change","","","(13,583",")","","","(31,469",")"],["Non-deductible executive compensation","","","1,414","","","","474"],["Tax less than book equity compensation","","","1,566","","","","4,933"],["Change in valuation allowances:"],["Federal valuation allowances & other","","","(76,553",")","","","124,631"],["State valuation allowances & other","","","(23,357",")","","","68,836"],["Permanent differences and other","","","83","","","","295"],["Total benefit for income taxes","","$","(9,743",")","","$","(25,552",")"],["Effective tax rate","","","(2.4","%)","","","3.5","%"]]
[[/GREPCENT_TABLE]]

We estimate our ability to utilize our deferred tax assets by analyzing the reversal patterns of our temporary differences, our loss carryforward periods and the Pennsylvania net operating loss carryforward limitations. Uncertainties such as future commodity prices can affect our calculations and can result in changes to the amount of valuation allowances.

Management’s Discussion and Analysis of Financial Condition, Cash Flows, Capital Resources and Liquidity

Cash Flows

The following table presents sources and uses of cash and cash equivalents for the last two years (in thousands):

[[GREPCENT_TABLE]]
[["","","2021","","","2020"],["Sources of cash and cash equivalents"],["Operating activities","","$","792,948","","","$","268,680"],["Disposal of assets","","","303","","","","246,127"],["Borrowing on credit facility","","","1,434,000","","","","2,076,000"],["Issuance of new senior notes","","","600,000","","","","850,000"],["Other","","","53,667","","","","23,045"],["Total sources of cash and cash equivalents","","$","2,880,918","","","$","3,463,852"],["Uses of cash and cash equivalents"],["Additions to natural gas and oil properties","","$","(393,478",")","","$","(405,617",")"],["Acreage purchases","","","(23,962",")","","","(26,816",")"],["Other property","","","(1,231",")","","","(2,873",")"],["Repayments on credit facility","","","(2,136,000",")","","","(1,851,000",")"],["Repayment of senior and subordinated notes","","","(63,324",")","","","(1,120,634",")"],["Repurchases of treasury stock","","","\u2014","","","","(22,992",")"],["Other","","","(48,959",")","","","(34,008",")"],["Total uses of cash and cash equivalents","","$","(2,666,954",")","","$","(3,463,940",")"]]
[[/GREPCENT_TABLE]]

49

Cash flows from operating activities are primarily affected by production volumes and commodity prices, net of the effects of settlements of our derivatives. Our cash flows from operating activities are also impacted by changes in working capital. We have historically maintained low cash and cash equivalent balances because we use available funds to reduce our bank debt. Short-term liquidity needs are satisfied by borrowings under our bank credit facility. Because of this, and because our principal source of operating cash flows (proved reserves to be produced in the following year) cannot be reported as working capital, we often have low or negative working capital. We sell a portion of our production at the wellhead under floating market contracts. From time to time, we enter into various derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future natural gas, NGLs and oil production. The production we hedge has and will continue to vary from year to year depending on, among other things, our expectation of future commodity prices. Since year-end 2021, we have entered into additional natural gas and NGLs hedges for 2022 through 2024. Any payments due to counterparties under our derivative contracts should ultimately be funded by prices received from the sale of our production. However, production receipts often lag payments to the counterparties. Any interim cash needs are funded by borrowings under the bank credit facility. As of December 31, 2021, we have entered into derivative agreements covering 381.3 Bcfe for 2022 and 139.2 Bcfe for 2023, not including our basis swaps.

Net cash provided from operating activities in 2021 was $792.9 million compared to $268.7 million in 2020. The increase in cash provided from operating activities is the result of a 86% increase in average realized prices (including all derivative settlements and third-party transportation costs) partially offset by a 5% decrease in production volumes. Net cash provided from operating activities is also affected by working capital changes or the timing of cash receipts and disbursements. Changes in working capital (as reflected in our consolidated statements of cash flows) for 2021 was an outflow of $241.7 million compared to an outflow of $53.9 million for 2020.

Disposal of assets in 2020 included proceeds of $246.1 million primarily from the sale of our North Louisiana assets.

Additions to natural gas and oil properties are our most significant use of cash and cash equivalents. These cash outlays are associated with our drilling and completion capital budget program. The following table shows capital expenditures by region and reconciles to additions to natural gas and oil properties as presented on our consolidated statements of cash flows for the last two years (in thousands):

[[GREPCENT_TABLE]]
[["","","2021","","","2020"],["Appalachia","","$","391,483","","","$","378,509"],["North Louisiana","","","\u2014","","","","1,987"],["Total","","","391,483","","","","380,496"],["Change in capital expenditure accrual for proved properties","","","1,995","","","","25,121"],["Additions to natural gas and oil properties","","$","393,478","","","$","405,617"]]
[[/GREPCENT_TABLE]]

Repayment of senior notes for 2021 includes the redemption of all of our senior subordinated notes due 2021, 2022 and 2023 and our senior notes due 2021. The prior year includes open market purchases of $161.0 million aggregate principal amount of various senior and senior subordinated notes due 2021, 2022 and 2023. In addition, 2020 also included two transactions where we repurchased $1.0 billion aggregate principal amount of various senior and senior subordinated notes due 2021, 2022 and 2023 where we paid an early cash tender to those note holders who tendered their notes within a ten business day offer period.

Liquidity and Capital Resources

Based on the current commodity price environment, we believe we have sufficient liquidity and capital resources to execute our business plan for the foreseeable future. We continue to manage the duration and level of our drilling and completion commitments in order to maintain flexibility with regard to our activity level and capital expenditures. As of December 31, 2021, we had cash on hand in the amount of $214.4 million.

Sources of Cash

We currently expect our 2022 capital program to be funded by cash flows from operations. During the year ended December 31, 2021, we generated $792.9 million of cash flows from operating activities. As of December 31, 2021, the remaining available borrowing capacity under our bank credit facility was $2.1 billion and we had $214.4 million cash on hand. Our borrowing base can be adjusted as a result of changes in commodity prices, acquisitions or divestitures of proved properties or financing activities. We may draw on our bank credit facility to meet short-term cash requirements. In early January 2022, we issued $500.0 million aggregate principal amount of new 4.75% senior notes due 2030, with the proceeds along with cash on hand used to fully redeem our 9.25% senior notes due 2026 in February 2022.

Although we expect cash flows and capacity under the existing credit facility to be sufficient to fund our expected 2022 capital program, we may also elect to raise funds through new debt or equity offerings or from other sources of financing. Any downgrades in our credit ratings could make it more difficult or expensive for us to borrow additional funds. All of our sources of liquidity can be affected by the general conditions of the broader economy, the global pandemic, force majeure events and fluctuations in commodity prices, operating costs and volumes produced, all of which affect us and our industry. We have no control over market prices for

50

natural gas, NGLs or oil, although we may be able to influence the amount of realized revenues through the use of derivative contracts as part of our commodity price risk management.

Bank Credit Facility

Our bank credit facility is secured by substantially all of our assets and has a maturity date of April 13, 2023. As of December 31, 2021, we had no outstanding borrowings under our bank credit facility and we maintain a borrowing base of $3.0 billion and aggregate lender commitments of $2.4 billion. We also have undrawn letters of credit of $338.0 million as of December 31, 2021.

The borrowing base is subject to regular, semi-annual redeterminations and is dependent on a number of factors but primarily the lender’s assessment of future cash flows. The next scheduled borrowing base redetermination is during the spring of 2022. We expect to extend the maturity of our bank credit facility prior to its current maturity date and plan to right-size the facility to provide us with sufficient access to liquidity. The terms of the facility are expected to reflect market, however the size and terms are uncertain at this time. We currently must comply with certain financial and non-financial covenants, including limiting dividend payments, debt incurrence and requirements that we maintain certain financial ratios (as defined in our bank credit agreement). We were in compliance with all such covenants at December 31, 2021.

Our daily weighted-average bank credit facility debt balance was $144.9 million for the year ended December 31, 2021 compared to $656.7 million for the year ended December 31, 2020. Borrowings under the bank credit facility can either be at the alternate base rate (“ABR,” as defined in the bank credit facility agreement) plus a spread ranging from 0.75% to 1.75% or at the LIBOR Rate (as defined in the bank credit facility agreement) plus a spread ranging from 1.75% to 2.75%. The applicable spread is dependent upon borrowings relative to the borrowing base. We may elect, from time to time, to convert all or any part of our LIBOR loans to base rate loans or to convert all or any of the base rate loans to LIBOR loans.

Uses of Cash

We use cash for the development, exploration and acquisition of natural gas and oil properties and for the payment of gathering, transportation and processing costs, operating, general and administrative costs, taxes and debt obligations, including interest. Expenditures for the development, exploration and acquisition of natural gas and oil properties are the primary use of our capital resources. During 2021, we spent $418.7 million on capital expenditures as reported in our consolidated statement of cash flows. The amount of our future capital expenditures will depend upon a number of factors including our cash flows from operating, investing and financing activities and our ability to execute our development program. In addition, the impact of commodity prices on investment opportunities, the availability of capital and the timing and results of our development activities may lead to changes in funding requirements for future development. We periodically review our budget to assess changes in current and projected cash flows, debt requirements and other factors.

We may from time to time repurchase or redeem all or portions of our outstanding debt securities for cash, through exchanges for other securities or a combination of both. Such repurchases or redemptions may be made in open market transactions and will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material. As part of our strategy for 2022, we will continue to focus on improving our debt metrics.

We expect our quarterly cash dividend to be reinstated in the second half of 2022. Details regarding the record and payment dates will be announced at such time the dividend is declared by our board of directors. In early 2022, the board approved an increase to our share repurchase program, where we are now authorized to repurchase an additional $500.0 million of our outstanding shares of common stock.

Shelf Registration

We have a universal shelf registration statement filed with the SEC under which we, as a "well-known seasoned issuer" for purposes of SEC rules, have the ability to sell an indeterminate amount of various types of debt and equity securities.

Proved Reserves

To maintain and grow production and cash flow, we must continue to develop existing proved reserves and locate or acquire new natural gas, NGLs and oil reserves. The following is a discussion of proved reserves, reserve additions and revisions and future net cash flows from proved reserves.

51

[[GREPCENT_TABLE]]
[["","","Year End December 31,"],["","","2021","","","2020"],["","","(Mmcfe)"],["Proved Reserves:"],["Beginning of year","","","17,203,114","","","","18,191,583"],["Reserve additions","","","1,602,769","","","","1,264,283"],["Reserve revisions","","","(252,876",")","","","(608,211",")"],["Sales","","","\u2014","","","","(828,085",")"],["Production","","","(777,523",")","","","(816,456",")"],["End of year","","","17,775,484","","","","17,203,114"],["Proved Developed Reserves:"],["Beginning of year","","","9,792,540","","","","9,902,467"],["End of year","","","10,417,887","","","","9,792,540"]]
[[/GREPCENT_TABLE]]

Our proved reserves at year-end 2021 were 17.8 Tcfe compared to 17.2 Tcfe at year-end 2020. Natural gas comprised approximately 64% of our proved reserves at year-end 2021.

Reserve Additions and Revisions. During 2021, we added 1.6 Tcfe of proved reserves from drilling activities and evaluation of proved areas in Pennsylvania. Approximately 72% of the 2021 reserve additions are attributable to natural gas. Our ethane reserves are intended to match volumes delivered under our existing long-term, extendable contracts. Revisions of previous estimates of a negative 252.9 Bcfe includes 1.3 Tcfe reserves reclassified to unproved because of previously planned wells not expected to be drilled within the original five year development horizon significantly offset by favorable pricing revisions of 22.6 Bcfe and positive performance revisions of 1.0 Tcfe. During 2020, we added 1.3 Tcfe of proved reserves from drilling activities and evaluation of proved areas in Pennsylvania. Approximately 80% of the 2020 reserve additions are attributable to natural gas. Revisions of previous estimates of a negative 608.2 Bcfe includes 961.1 Bcfe reserves reclassified to unproved because of previously planned wells not expected to be drilled within the original five year development horizon, negative pricing revisions of 67.9 Bcfe somewhat offset by positive performance revisions of 420.8 Bcfe.

Sales. In 2020, we sold 828.1 Bcfe of reserves related to the sale of our North Louisiana assets.

Future Net Cash Flows. At December 31, 2021, the present value (discounted at 10%) of estimated future net cash flows from our proved reserves was $14.9 billion. The present value of our estimated future net cash flows at December 31, 2020 was $3.0 billion. This present value was calculated based on the unweighted average first-day-of-the-month oil and gas prices for the prior twelve months held flat for the life of the reserves, in accordance with SEC rules. At December 31, 2021, the after-tax present value of estimated future net cash flows from our proved reserves was $12.5 billion compared to $2.8 billion at December 31, 2020.

The present value of future net cash flows does not purport to be an estimate of the fair market value of our proved reserves. An estimate of fair value would also take into account, among other things, anticipated changes in future prices and costs, the expected recovery of reserves in excess of proved reserves and a discount factor more representative of the time value of money to the evaluating party and the perceived risks inherent in producing oil and gas.

Capitalization and Dividend Payments

As of December 31, 2021 and 2020, our total debt and capitalization were as follows (in thousands):

[[GREPCENT_TABLE]]
[["","","2021","","","2020"],["Bank debt","","$","\u2014","","","$","693,123"],["Senior notes","","","2,925,787","","","","2,355,223"],["Senior subordinated notes","","","\u2014","","","","37,261"],["Total debt","","","2,925,787","","","","3,085,607"],["Stockholders\u2019 equity","","","2,085,663","","","","1,637,535"],["Total capitalization","","$","5,011,450","","","$","4,723,142"],["Debt to capitalization ratio","","","58.4","%","","","65.3","%"]]
[[/GREPCENT_TABLE]]

The amount of future dividends is subject to declaration by the board of directors and primarily depends on earnings, capital expenditures and various other factors.

52

Cash Contractual Obligations

Our contractual obligations include long-term debt, operating leases, derivative obligations, asset retirement obligations, and transportation, gathering and processing commitments. As of December 31, 2021, we do not have any capital leases or any significant off-balance sheet debt or other such unrecorded obligations and we have not guaranteed any debt of any unrelated party. As of December 31, 2021, we had a total of $338.0 million of letters of credit outstanding under our bank credit facility. The table below provides estimates of the timing of future payments that we are obligated to make based on agreements in place at December 31, 2021. In addition to the contractual obligations listed in the table below, our consolidated balance sheet at December 31, 2021 reflects accrued interest payable on our bank debt of $1.6 million, which is payable in first quarter 2022. We expect to make annual interest payments through the end of each note maturity, based upon the amounts outstanding at December 31, 2021, of $36.6 million on our 4.875% senior notes, $35.1 million on our 5.00% senior notes, $2.9 million on our 5.875% senior notes, $49.5 million on our 8.25% senior notes and $78.6 million on our 9.25% senior notes. We redeemed in full the 9.25% senior notes in February 2022.

The following summarizes our contractual financial obligations at December 31, 2021 and their future maturities. We expect to fund these contractual obligations with cash generated from operating activities, and, if necessary, borrowings under our bank credit facility, or other sources (in thousands).

[[GREPCENT_TABLE]]
[["","","Payment due by period"],["","","2022","","","2023","","","2024","","","2025 and 2026","","","Thereafter","","","Total"],["Debt:"],["Bank debt due 2023 (a)","","$","\u2014","","","$","\u2014","","","$","\u2014","","","$","\u2014","","","$","\u2014","","","$","\u2014"],["5.00% senior notes due 2022","","","169,589","","","","\u2014","","","","\u2014","","","","\u2014","","","","\u2014","","","","169,589"],["5.875% senior notes due 2022","","","48,528","","","","\u2014","","","","\u2014","","","","\u2014","","","","\u2014","","","","48,528"],["5.00% senior notes due 2023","","","\u2014","","","","532,335","","","","\u2014","","","","\u2014","","","","\u2014","","","","532,335"],["4.875% senior notes due 2025","","","\u2014","","","","\u2014","","","","\u2014","","","","750,000","","","","\u2014","","","","750,000"],["9.25% senior notes due 2026","","","\u2014","","","","\u2014","","","","\u2014","","","","850,000","","","","\u2014","","","","850,000"],["8.25% senior notes due 2029","","","\u2014","","","","\u2014","","","","\u2014","","","","\u2014","","","","600,000","","","","600,000"],["Other obligations:","","","","","","","","","","","","","","","","","","\u2014"],["Operating leases, net","","","21,282","","","","7,207","","","","6,546","","","","12,635","","","","2,627","","","","50,297"],["Software licenses and other","","","2,767","","","","2,191","","","","51","","","","64","","","","16","","","","5,089"],["Derivative obligations (b)","","","162,767","","","","8,565","","","","\u2014","","","","\u2014","","","","\u2014","","","","171,332"],["Transportation and gathering commitments(c)","","","801,974","","","","784,712","","","","768,059","","","","1,305,611","","","","3,520,105","","","","7,180,461"],["Asset retirement obligation liability (d)","","","5,310","","","","50","","","","\u2014","","","","\u2014","","","","90,476","","","","95,836"],["Total contractual obligations (e)","","$","1,212,217","","","$","1,335,060","","","$","774,656","","","$","2,918,310","","","$","4,213,224","","","$","10,453,467"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["(a)","As of December 31, 2021, we had no outstanding borrowings under our bank credit facility."],["(b)","Derivative obligations represent net liabilities determined in accordance with master netting arrangements for commodity derivatives that were valued as of December 31, 2021. Our derivatives are measured and recorded at fair value and are subject to market and credit risk. The ultimate liquidation value will be dependent upon actual future commodity prices which may differ materially from the inputs used to determine fair value as of December 31, 2021. See Note 9 to our consolidated financial statements."],["(c)","The obligations above represent our minimum financial commitments pursuant to the terms of these contracts. Our actual expenditures may exceed these minimum commitments."],["(d)","The amount above represents the discounted values. There are inherent uncertainties surrounding the obligations and the actual amount and timing may differ from our estimates. See Note 8 to our consolidated financial statements."],["(e)","This table excludes the liability for the deferred compensation plans since these obligations will be funded with existing plan assets and does not include obligations to taxing authorities."]]
[[/GREPCENT_TABLE]]

In addition to the amounts included in the above table, we have entered into an additional agreement which is contingent on certain pipeline modifications and/or construction for natural gas volumes of 25,000 mcf per day and is expected to begin in 2022 with a six-year term.

Not included in the table above is our estimate of accrued contractual obligations related to certain obligations retained by us after our divestiture of our North Louisiana assets. These contractual obligations are related to gathering, processing and transportation agreements including certain minimum volume commitments. There are inherent uncertainties surrounding the retained obligation and, as a result, the determination of the accrued obligation required significant judgement and estimation. The actual settlement amount and timing may differ from our estimates. See also Note 3, Note 14 and Note 15 to our consolidated financial statements. As of December 31, 2021, the carrying value of this obligation was $416.4 million (discounted) and is included in divestiture contract obligation in our consolidated balance sheet. As of December 31, 2021, our estimated settlement of this retained obligation based on a discounted value is as follows (in thousands):

53

[[GREPCENT_TABLE]]
[["","","Year Ended December 31,"],["2022","","$","91,120"],["2023","","","71,277"],["2024","","","58,401"],["2025","","","51,688"],["2026","","","36,971"],["Thereafter","","","106,942"],["","","$","416,399"]]
[[/GREPCENT_TABLE]]

Delivery Commitments

We have various volume delivery commitments that are related to our Marcellus Shale properties. We expect to be able to fulfill our contractual obligations from our own production; however, we may purchase third-party volumes to satisfy our commitments or pay demand fees for commitment shortfalls, should they occur. As of December 31, 2021, our delivery commitments through 2031 were as follows:

[[GREPCENT_TABLE]]
[["Year Ending December 31,","","Natural Gas (mmbtu per day)","","","Ethane and Propane (bbls per day)"],["2022","","","588,158","","","55,000"],["2023","","","500,710","","","39,932"],["2024","","","253,566","","","35,000"],["2025","","","182,493","","","35,000"],["2026","","","158,301","","","35,000"],["2027","","","100,000","","","35,000"],["2028","","","100,000","","","35,000"],["2029","","","100,000","","","20,000"],["2030","","","\u2014","","","20,000"],["2031","","","\u2014","","","20,000"]]
[[/GREPCENT_TABLE]]

In addition to the amounts included in the above table, we have contracted with a pipeline company through 2037 to deliver ethane production volumes from our Marcellus Shale wells. These agreements and related fees, which are contingent upon facility construction and/or modification, are for 3,000 bbls per day starting in 2022, increasing to 18,000 bbls per day in 2027 and increasing again to 25,000 bbls per day in 2029 then declining to 10,000 bbls per day in 2034 and declining again to 3,000 bbls per day through the end of the term in 2037.

Other

We lease acreage that is generally subject to lease expiration if initial wells are not drilled within a specified period, generally between three and five years. We do not expect to lose significant lease acreage because of failure to drill due to inadequate capital, equipment or personnel. However, based on our evaluation of prospective economics, including the cost of infrastructure to connect production, we have allowed acreage to expire and will allow additional acreage to expire in the future. To date, our expenditures to comply with environmental or safety regulations have not been a significant component of our cost structure and are not expected to be significant in the future. However, new regulations, enforcement policies, claims for damages, or other events could result in significant future costs.

Interest Rates

At December 31, 2021, we had $2.9 billion of debt outstanding which bears interest at fixed rates averaging 6.9%. In January 2022, we issued $500.0 million of 4.75% senior notes due 2030 and we used the proceeds, along with cash on hand and our bank credit facility to fully redeem our 9.25% senior notes. After this transaction, our debt outstanding will bear interest at fixed rates averaging 5.7%.

Off-Balance Sheet Arrangements

We do not currently utilize any off-balance sheet arrangements with unconsolidated entities to enhance our liquidity or capital resources position. However, as is customary in the natural gas and oil industry, we have various contractual work commitments which are described above under cash contractual obligations.

54

Inflation and Changes in Prices

Our revenues, the value of our assets and our ability to obtain bank loans or additional capital on attractive terms have been and will continue to be affected by changes in natural gas, NGLs and oil prices and the costs to produce our reserves. Natural gas, NGLs and oil prices are subject to significant fluctuations that are beyond our ability to control or predict. Although certain of our costs and expenses are affected by general inflation, inflation does not normally have a significant effect on our business. We expect costs in 2022 to continue to be a function of supply and demand. Natural gas, NGLs and oil prices have remained volatile and unpredictable. However, we continue to focus on improving our cost structure.

Management’s Discussion of Critical Accounting Estimates

Our discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at year-end and the reported amounts of revenues and expenses during the year. Accounting estimates are considered to be critical if (1) the nature of the estimates and assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to changes; and (2) the impact of the estimates and assumptions on financial condition or operating performance is material. Actual results could differ from the estimates and assumptions used.

Estimated Quantities of Net Reserves

We use the successful efforts method of accounting for natural gas and oil producing activities as opposed to the alternate acceptable full cost method. We believe that net assets and net income are more conservatively measured under the successful efforts method of accounting than under the full cost method, particularly during periods of active exploration. One difference between the successful efforts method of accounting and the full cost method is that under the successful efforts method, all exploratory dry holes and geological and geophysical costs are charged against earnings during the periods they occur; whereas, under the full cost method of accounting, such costs are capitalized as assets, pooled with the costs of successful wells and charged against earnings of future periods as a component of depletion expense. Under the successful efforts method of accounting, successful exploration drilling costs and all development costs are capitalized and these costs are systematically charged to expense using the units of production method based on proved developed natural gas and oil reserves as estimated by our engineers and audited by independent engineers. Costs incurred for exploratory wells that find reserves that cannot yet be classified as proved are capitalized on our balance sheet if (1) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (2) we are making sufficient progress assessing the reserves and the economic and operating viability of the project. Proven property leasehold costs are amortized to expense using the units of production method based on total proved reserves. Properties are assessed for impairment as circumstances warrant (at least annually) and impairments to value are charged to expense. The successful efforts method inherently relies upon the estimation of proved reserves, which includes proved developed and proved undeveloped volumes.

Proved reserves are defined by the SEC as those volumes of natural gas, NGLs, condensate and crude oil that geological and engineering data demonstrate with reasonable certainty are recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are volumes expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves include reserves for which a development plan has been adopted indicating each location is scheduled to be drilled within five years from the date it was booked as proved reserves, unless specific circumstances justify a longer time. Although our engineers are knowledgeable of and follow the guidelines for reserves established by the SEC, the estimation of reserves requires engineers to make a significant number of assumptions based on professional judgment. Reserve estimates are updated at least annually and consider recent production levels and other technical information. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information, including reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price and cost changes and other economic factors. Changes in natural gas, NGLs and oil prices can lead to a decision to start up or shut in production, which can lead to revisions to reserve quantities. Reserve revisions in turn cause adjustments in our depletion rates. We cannot predict what reserve revisions may be required in future periods. Reserve estimates are reviewed and approved by our Senior Vice President of Reservoir Engineering and Economics, who reports directly to our President and Chief Executive Officer. To further ensure the reliability of our reserve estimates, we engage independent petroleum consultants to audit our estimates of proved reserves. Estimates prepared by third parties may be higher or lower than those included herein. Independent petroleum consultants audited approximately 97% of our reserves in both 2021 and 2020. Historical variances between our reserve estimates and the aggregate estimates of our consultants have been less than 5%. The reserves included in this report are those reserves estimated by our petroleum engineering staff. For additional discussion, see Items 1 & 2. Business and Properties – Proved Reserves.

Reserves are based on the weighted average of commodity prices during the 12-month period, using the closing prices on the first day of each month, as defined by the SEC. When determining the December 31, 2021 proved reserves for each property, benchmark prices are adjusted using price differentials that account for property-specific quality and location differences. If prices in the future average below prices used to determine reserves at December 31, 2021, it could have an adverse effect on our estimates of

55

proved reserves. It is difficult to estimate the magnitude of any potential price change and the effect on proved reserves due to numerous factors (including commodity prices and performance revisions).

Depletion rates are determined based on reserve quantity estimates and the capitalized costs of producing properties. As the estimated reserves are adjusted, the depletion expense for a property will change, assuming no change in production volumes or the capitalized costs. While total depletion expense for the life of a property is limited to the property’s total cost, proved reserve revisions result in a change in the timing of when depletion expense is recognized. Downward revisions of proved reserves may result in an acceleration of depletion expense, while upward revisions tend to lower the rate of depletion expense recognition. Based on proved reserves at December 31, 2021, we estimate that a 1% change in proved reserves would increase or decrease 2022 depletion expense by approximately $4.0 million (based on current production estimates). Estimated reserves are used as the basis for calculating the expected future cash flows from property asset groups, which are used to determine whether that property may be impaired. Reserves are also used to estimate the supplemental disclosure of the standardized measure of discounted future net cash flows relating to natural gas and oil producing activities and reserve quantities in Note 17 to our consolidated financial statements. Changes in the estimated reserves are considered a change in estimate for accounting purposes and are reflected on a prospective basis. It should not be assumed that the standardized measure is the current market value of our estimated proved reserves.

Fair Value Estimates

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. There are three approaches for measuring the fair value of assets and liabilities: the market approach, the income approach and the cost approach, each of which includes multiple valuation techniques. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. The income approach uses valuation techniques to measure fair value by converting future amounts, such as cash flows or earnings, into a single present value, or range of present values, using current market expectations about those future amounts. The cost approach is based on the amount that would currently be required to replace the service capacity of an asset. This is often referred to as current replacement cost. The cost approach assumes that the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset of comparable utility, adjusted for obsolescence.

The fair value accounting standards do not prescribe which valuation technique should be used when measuring fair value and do not prioritize among the techniques. These standards establish a fair value hierarchy that prioritizes the inputs used in applying the various valuation techniques. Inputs broadly refer to the assumptions that market participants use to make pricing decisions, including assumptions about risk. Level 1 inputs are given the highest priority in the fair value hierarchy, while Level 3 inputs are given the lowest priority. The three levels of the fair value hierarchy are as follows:

•
Level 1-Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the measurement date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

•
Level 2-Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the measurement date.

•
Level 3-Unobservable inputs for which there is little, if any, market activity for the asset or liability being measured. These inputs reflect management’s best estimates of the assumptions market participants would use in determining fair value.

Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy. See Note 10 to the consolidated financial statements for disclosures regarding our fair value measurements.

Significant uses of fair value measurement include:

•
impairment assessments of long-lived assets,

•
recorded value of certain derivative instruments and

•
the initial recording of retained liabilities.

The need to test long-lived assets for impairment can be based on several indicators, including a significant reduction in commodity prices, reductions to our capital budget, unfavorable adjustments to reserves, significant changes in the expected timing of production, other changes to contracts or changes in the regulatory environment in which a property is located.

56

Exit Cost Estimates

Our consolidated balance sheets include accrued exit cost liabilities primarily related to retained gathering, processing and transportation contracts in Louisiana. Inherent in the initial fair value calculation of these exit costs associated with our North Louisiana divestiture are numerous assumptions and judgments including the ultimate amounts to be paid, the credit-adjusted discount rates, the development plans of the buyer and our probability weighted forecast of those drilling plans, market conditions and the ultimate usage by the buyer of each facility included in the agreement. A significant portion of this obligation is a gas processing agreement that includes a deficiency payment if the minimum volume commitment is not met and we must assess the likelihood and amount of production volumes flowing to this facility. In addition, our agreement includes additional transportation agreements that are based on contractual rates applied to a minimum volume usage. We have made significant judgments and estimates regarding the timing and amount of these liabilities. We based our initial fair value estimate on assumptions we believe to be reasonable and likely to occur. If the drilling development does not occur as we have assumed, the carrying value of the liability could increase by approximately $30.0 million. Changes in other assumptions, such as the estimate of production volumes flowing to processing facilities, could result in a higher liability. If we assume the flow of production volumes was held flat through the end of the contract, the liability could increase by approximately $20.0 million. We continue to regularly monitor our estimates and in the future may be required to adjust our estimates based on facts and circumstances. See Note 14 and Note 15 to our consolidated financial statements for a further discussion of these costs.

Impairment Assessments of Natural Gas and Oil Properties

Long-lived assets in use are assessed for impairment whenever changes in facts and circumstances indicate that the carrying value of the assets may not be recoverable. For purposes of an impairment evaluation, long-lived assets must be grouped at the lowest level for which independent cash flows can be identified, which generally is field-by-field, in certain instances, by logical grouping of assets if there is significant shared infrastructure or contractual terms that cause economic interdependency amongst separate, discrete fields. If the sum of the undiscounted estimated cash flows from the use of the asset group and its eventual disposition is less than the carrying value of an asset group, the carrying value is written down to the estimated fair value. During 2019, a change in business strategy employed by management in North Louisiana and the possibility of a divestiture of these assets triggered an assessment of these long-lived assets for impairment. We estimated the fair values using a discounted net cash flow model or an income approach and we recognized an impairment. As of December 31, 2021, our estimated undiscounted cash flows relating to our remaining long-lived assets significantly exceeded their carrying values. See Note 10 to the consolidated financial statements for discussion of impairments recorded in the last three years and the related fair value measurements.

Fair value calculated for the purpose of testing our natural gas and oil properties for impairment is estimated using the present value of expected future cash flows method and comparative market prices when appropriate. Significant judgment is involved in performing these fair value estimates since the results are based on forecasted assumptions. Significant assumptions include:

•
Future crude oil and condensate, NGLs and natural gas prices. Our estimates of future prices are based on market information including published futures prices. Although these commodity prices may experience extreme volatility in any given year, we believe long-term industry prices are driven by market supply and demand. The prices we use in our fair value estimates are consistent with those used in our planning and capital investment reviews. There has been significant volatility in crude oil and condensate, NGLs and natural gas prices and estimates of such future prices are inherently imprecise. See Item 1A. Risk Factors for further discussion on commodity prices.

•
Estimated quantities of crude oil and condensate, NGLs and natural gas. Such quantities are based on risk adjusted proved and probable reserves and resources such that the combined volumes represent the most likely expectation of recovery. See Item 1A. Risk Factors for further discussion on reserves.

•
Expected timing of production. Production forecasts are the outcome of engineering studies which estimate reserves, as well as expected capital programs. The actual timing of the production could be different than the projection. Cash flows realized later in the projection period are less valuable than those realized earlier due to the time value of money. The expected timing of production that we use in our fair value estimates is consistent with that used in our planning and capital investment reviews.

•
Discount rate commensurate with the risks involved. We apply a discount rate to our expected cash flows based on a variety of factors, including market and economic conditions, operational risk, regulatory risk and political risk. A higher discount rate decreases the net present value of cash flows.

•
Future capital requirements. Our estimates of future capital requirements consider the assumptions utilized by management for internal planning and budgeting.

We base our fair value estimates on projected financial information which we believe to be reasonably likely to occur. An estimate of the sensitivity to changes in assumptions in our undiscounted cash flow calculations is not practicable, given the numerous

57

assumptions (e.g. reserves, pace and timing of development plans, commodity prices, capital expenditures, operating costs, drilling and development costs, inflation and discount rates) that can materially affect our estimates. Unfavorable adjustments to some of the above listed assumptions would likely be offset by favorable adjustments in other assumptions. For example, the impact of sustained reduced commodity prices on future undiscounted cash flows would likely be partially offset by lower costs.

Commodity Derivative Instruments

All commodity derivative instruments are recorded on our consolidated balance sheets as either an asset or a liability measured at its fair value. Fair value measurements for certain of our commodity derivatives are based upon, among other things, option pricing models, futures, volatility, time to maturity and credit risk and are discussed in Note 10 to our consolidated financial statements. We regularly validate our fair value measurements through the review of counterparty statements, by corroborating original sources of inputs and monitoring changes in valuation methods and assumptions. Additional information about derivatives and their valuation may be found in Item 7A. Quantitative and Qualitative Disclosures about Market Risk.

Asset Retirement Obligations

We have significant obligations to remove tangible equipment and restore the surface at the end of natural gas and oil production operations. Removal and restoration obligations are primarily associated with plugging and abandoning wells. Estimating the future asset removal costs is difficult and requires us to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.

Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate retirement costs, inflation factors, credit-adjusted discount rates, timing of retirement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation (“ARO”), a corresponding adjustment is made to the natural gas and oil property balance. For example, as we analyze actual plugging and abandonment information, we may revise our estimate of current costs, the assumed annual inflation of the costs and/or the assumed productive lives of our wells. See Note 8 to the consolidated financial statements for disclosures regarding our asset retirement obligation estimates. In addition, increases in the discounted ARO resulting from the passage of time are reflected as accretion expense, a component of depletion, depreciation and amortization in the accompanying consolidated statements of operations. Because of the subjectivity of assumptions and the relatively long lives of most of our wells, the costs to ultimately retire our wells may vary significantly from prior estimates. An estimate of the sensitivity to operating results of other assumptions that had been used in recording these liabilities is not practical because of the number of obligations that must be assessed, the number of underlying assumptions and the wide range of possible assumptions.

Income Taxes

We are subject to income and other taxes in all areas in which we operate. For financial reporting purposes, we provide taxes at rates applicable for the appropriate tax jurisdictions. Estimates of amounts of income tax to be recorded involve interpretation of complex tax laws. Our effective tax rate is subject to variability as a result of factors other than changes in federal and state tax rates and/or changes in tax laws which could affect us. Our effective rate is also affected by changes in the allocation of revenue among states.

Our consolidated balance sheets include deferred tax assets. Deferred tax assets arise when expenses are recognized in the financial statements before they are recognized in the tax returns or when income items are recognized in the tax returns before they are recognized in the financial statements. Deferred tax assets also arise when operating losses or tax credits are available to offset tax payments due in future years. Ultimately, realization of a deferred tax asset depends on the existence of sufficient taxable income within the future periods to absorb future deductible temporary differences, loss carryforwards or credits.

In assessing the potential realization of deferred tax assets, management must consider whether it is more likely than not (a likelihood of more than 50%) that some portion or all of the deferred tax assets will be realized. Management considers all available evidence (both positive and negative) in determining whether a valuation allowance is required. Such evidence includes the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment and judgment is required in considering the relative weight of negative and positive evidence. We continue to monitor facts and circumstances in the reassessment of the likelihood that operating loss carryforwards, credits and other deferred tax assets will be utilized prior to their expiration. As a result, we may determine that an additional deferred tax asset valuation allowance should be established. In determining whether a valuation allowance is required for our deferred tax asset balances, we consider, among other factors, current financial position, results of operations, projected future taxable income, tax planning strategies and new legislation. Significant judgment is involved in this determination as we are required to make assumptions about future commodity prices, projected production, development activities, profitability of future business strategies and forecasted economics in the oil and gas industry. Additionally, changes in the effective tax rate resulting from changes in tax law and our level of earnings may limit utilization of deferred tax assets and will affect valuation of deferred tax balances in the future. Changes in judgment regarding future realization of

58

deferred tax assets may result in a reversal of all or a portion of the valuation allowance. In the period that determination is made, our net income will benefit from a lower effective tax rate.

We believe our net deferred tax assets, after valuation allowances, will ultimately be realized. During 2021, we decreased our valuation allowances against our state net operating loss carryforwards, basis differences and credits from $226.5 million as of December 31, 2020 to $203.1 million as of December 31, 2021. The federal valuation allowances decreased from $152.5 million as of December 31, 2020 to $68.0 million as of December 31, 2021. See Note 5 to our consolidated financial statements for further information concerning our income taxes.

An estimate of the sensitivity to changes in our assumptions resulting in future income calculations is not practical, given the numerous assumptions that can materially affect our estimates. Unfavorable adjustments to some of the assumptions would likely be offset by favorable adjustments in other assumptions. For example, the impact of sustained reduced commodity prices on future taxable income would likely be partially offset by lower capital expenditures.

We may be challenged by taxing authorities over the amount and/or timing of recognition of revenues and deductions in our various income tax returns. Although we believe that we have adequately provided for all taxes, income or losses could occur in the future due to changes in estimates or resolution of outstanding tax matters.

Accounting Standards Not Yet Adopted

None that are expected to have a material impact.

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