# RANGE RESOURCES CORP (RRC) FY 2023 MD&A

Verbatim Item 7 Management's Discussion and Analysis from RANGE RESOURCES CORP's 10-K for fiscal year 2023.

SEC filing source: https://www.sec.gov/Archives/edgar/data/315852/000095017024018046/rrc-20231231.htm
Accession: 0000950170-24-018046
Filing date: 2024-02-21
Report date: 2023-12-31
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/
Previous year: /company/RRC/mda/fy2022/ (FY 2022)
Next year: /company/RRC/mda/fy2024/ (FY 2024)

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, 2023 and 2022. For similar discussions of the year ended December 31, 2022 compared to December 31, 2021 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, 2022, which was filed with the SEC on February 27, 2023.

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 flows 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 investments;

•
optimizing drilling, completion and operational efficiencies;

•
maintaining a competitive cost structure;

•
managing price risk through the hedging of our production; and

•
managing 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 reinvestment; 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.

Key 2023 highlights include:

Financial and operating results:

•
We recorded net income of $871.1 million for the year ended December 31, 2023;

•
Average daily production was 2.14 Bcfe during the year;

•
Repurchased 715,000 shares of common stock via the share repurchase program leaving $1.1 billion available under the repurchase program;

•
Paid dividends of $77.2 million, ending the year with $212.0 million in cash on hand; and

•
Executed opportunistic debt repurchases of $61.6 million in the open market.

37

Corporate sustainability highlights and initiatives:

•
Completed the MiQ certification for our Southwest Pennsylvania assets and earned an "A" grade;

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

•
Implemented the use of compressed air pneumatic controllers;

•
Achieved a 28% reduction in number of workforce recordable injuries (both employee and contractor) with a Total Recordable Incident Rate of 0.34;

•
Achieved a 70% reduction in preventable vehicle incidents with six incidents in 2023; and

•
Continued board of directors refreshment through the appointment of one new director.

Management’s Discussion and Analysis of Results of Operations

Commodity prices have remained volatile. Benchmarks for natural gas, oil and NGLs decreased in 2023 compared to 2022 and, as a result, we experienced significant decreases in our price realizations when compared to the same period of 2022. Despite lower prices, we continued to focus on creating long-term value for our stockholders along with positioning ourselves to be a responsible and reliable supplier of natural gas.

Overview of 2023 Results

During 2023, we recognized net income of $871.1 million, or $3.57 per diluted common share compared to $1.2 billion, or $4.69 per diluted common share during 2022. The decrease in net income for the year ended December 31, 2023 when compared to 2022 is primarily due to significantly lower realized prices.

For the year ended December 31, 2023, we experienced a decrease in revenue from the sale of natural gas, NGLs and oil due to a 41% decrease in net realized prices (average prices including all derivative settlements and third-party transportation costs paid by us) when compared to 2022. Daily production in 2023 averaged 2.14 Bcfe compared to 2.12 Bcfe in 2022.

During 2023, our financial and operating performance included the following results:

•
revenue from the sale of natural gas, NGLs and oil decreased 52% from the same period of 2022 with a 53% decrease in average realized prices (before cash settlements on our derivatives) partially offset by slightly higher production volumes;

•
revenue from the sale of natural gas, NGLs and oil (including cash settlements on our derivatives) decreased 30% from the same period of 2022;

•
transportation, gathering, processing and compression expense per mcfe was $1.43 in 2023 compared to $1.61 in the same period of 2022 primarily due to the impact of lower commodity prices;

•
direct operating expense per mcfe was $0.12 in 2023 compared to $0.11 in the same period of 2022 due to higher workover costs;

•
general and administrative expense per mcfe for 2023 decreased 5% from the same period of 2022 due to lower stock-based compensation;

•
interest expense per mcfe for 2023 decreased 24% from the same period of 2022 due to lower debt balances;

•
our DD&A rate per mcfe for 2023 decreased 2% from the same period of 2022;

•
drilled 47.4 net wells with a 100% success rate;

•
cash flow from operating activities for 2023 was 48% lower than the same period of 2022 due to lower commodity prices; and

•
our capital budget spending for 2023 was $613.6 million, which was within our initially announced range of $570.0 million to $615.0 million.

The year ended December 31, 2023 also included the following highlights to enhance our balance sheet, return capital to investors and preserve liquidity:

•
paid $77.2 million in dividends or $0.32 per share compared to $0.16 in 2022;

•
repurchased $19.0 million of our common stock compared to $399.7 million in 2022;

•
repurchased in the open market $61.6 million face value of our 4.875% senior notes due 2025 at a discount; and

•
enhanced liquidity with the accumulation of cash on hand of $212.0 million along with $1.3 billion available under our credit facility.

38

We generated $977.9 million of cash from operating activities in 2023, a decrease of $886.9 million from 2022 which reflects significantly lower realized prices partially offset by lower comparative working capital outflows.

Acquisitions

During 2023, we invested $40.1 million to acquire unproved acreage compared to $28.7 million in 2022. We continue selective acreage leasing and lease renewals to consolidate our acreage positions in the Marcellus Shale play in Pennsylvania.

2024 Outlook

As we enter 2024, we believe we are positioned for sustainable long-term success. For 2024, we expect our capital budget to be in the range of $620 million to $670 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 2024 capital budget to achieve production similar to our 2023 production. Our 2024 capital budget is focused on continuing to improve corporate returns and generating free cash flow. We expect it to be funded with operating 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 2024 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 2024.

Market Conditions

We believe we are positioned for sustainable long-term success. We continue to monitor the impact of the actions of OPEC and other large producing nations, the Russia-Ukraine conflict, hostilities in the Middle East, global inventories of oil and gas, future monetary policy and governmental policies aimed at transitioning towards lower carbon energy and we expect prices for some or all of the commodities we produce to remain volatile given the complex dynamics of supply and demand that exist in the global market. In fourth quarter 2023, natural gas prices declined based on the relatively mild early days of winter and delays to a large liquefied natural gas export project in-service date. Longer term natural gas futures prices have remained stronger 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 infrastructure constraints, 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 United States liquefied natural gas exports, domestic industrial gas demand and power generation. Other factors such as geopolitical disruptions, supply chain disruptions, cost inflation, concerns over a potential economic recession and the pace and extent of tightening global monetary policy may impact the demand for oil, natural gas and NGLs. We continue to assess and monitor the impact and consequences of these factors on our operations.

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 decreased, when compared to December 2023, with the average NYMEX monthly settlement price for natural gas decreasing to $2.49 per mcf for February 2024 with the recent mild winter weather. Crude oil prices have increased, when compared to December 2023, to $73.86 per barrel in January 2024. The following table lists related benchmarks for natural gas, oil and NGLs composite prices for the years ended December 31, 2023 and 2022.

[[GREPCENT_TABLE]]
[["","","Year Ended December 31,"],["","","2023","","","2022"],["Benchmarks:"],["Average NYMEX prices (a)"],["Natural gas (per mcf)","","$","2.75","","","$","6.64"],["Oil (per bbl)","","$","77.54","","","$","94.90"],["Mont Belvieu NGLs composite (per gallon) (b)","","$","0.56","","","$","0.90"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["(a)","Based on average of monthly last day settlement prices on the New York Mercantile Exchange (\"NYMEX\")."],["(b)","Based on our estimated NGLs product composition per barrel."]]
[[/GREPCENT_TABLE]]

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.

39

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 2023, natural gas, NGLs and oil sales decreased 52% from 2022 with a 53% decrease in realized prices (excluding cash settlements on our derivatives) partially offset by slightly higher production volumes. 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,"],["","","2023","","","2022","","","Change","","","% Change"],["Natural gas, NGLs and Oil sales"],["Natural gas","","$","1,234,308","","","$","3,364,111","","","$","(2,129,803",")","","","(63","%)"],["NGLs","","","933,791","","","","1,308,574","","","","(374,783",")","","","(29","%)"],["Oil and condensate","","","166,562","","","","238,407","","","","(71,845",")","","","(30","%)"],["Total natural gas, NGLs and oil sales","","$","2,334,661","","","$","4,911,092","","","$","(2,576,431",")","","","(52","%)"]]
[[/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. Our production for the last two years is set forth in the following table:

[[GREPCENT_TABLE]]
[["","Year Ended December 31,"],["","2023","","","2022","","","Change","","","% Change"],["Production (a)"],["Natural gas (mcf)","","538,084,671","","","","539,442,624","","","","(1,357,953",")","","","\u2014","%"],["NGLs (bbls)","","37,939,700","","","","36,392,033","","","","1,547,667","","","","4","%"],["Crude oil and condensate (bbls)","","2,475,306","","","","2,715,681","","","","(240,375",")","","","(9","%)"],["Total (mcfe) (b)","","780,574,707","","","","774,088,908","","","","6,485,799","","","","1","%"],["Average daily production (a)"],["Natural gas (mcf)","","1,474,205","","","","1,477,925","","","","(3,720",")","","","\u2014","%"],["NGLs (bbls)","","103,944","","","","99,704","","","","4,240","","","","4","%"],["Crude oil and condensate (bbls)","","6,782","","","","7,440","","","","(658",")","","","(9","%)"],["Total (mcfe) (b)","","2,138,561","","","","2,120,792","","","","17,769","","","","1","%"]]
[[/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]]

40

Our average realized price (including all derivative settlements and third-party transportation costs paid by Range) received during 2023 was $1.88 per mcfe compared to $3.17 per mcfe in 2022. The majority of our production is sold at market-sensitive prices. Generally, if the related commodity index declines, the price we receive for our production will also decline. 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 income. 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,"],["","2023","","","2022","","","Change","","","% Change"],["Average Prices"],["Average sales prices (excluding derivative settlements):"],["Natural gas (per mcf)","$","2.29","","","$","6.24","","","$","(3.95",")","","","(63","%)"],["NGLs (per bbl)","","24.61","","","","35.96","","","","(11.35",")","","","(32","%)"],["Crude oil (per bbl)","","67.29","","","","87.79","","","","(20.50",")","","","(23","%)"],["Total (per mcfe) (a)","","2.99","","","","6.34","","","","(3.35",")","","","(53","%)"],["Average realized prices (including all derivative settlements):"],["Natural gas (per mcf)","$","2.77","","","$","4.16","","","$","(1.39",")","","","(33","%)"],["NGLs (per bbl)","","24.61","","","","35.62","","","","(11.01",")","","","(31","%)"],["Crude oil (per bbl)","","62.77","","","","57.39","","","","5.38","","","","9","%"],["Total (per mcfe) (a)","","3.31","","","","4.78","","","","(1.47",")","","","(31","%)"],["Average realized prices (including all derivative settlements and third-party transportation costs paid by Range):"],["Natural gas (per mcf)","$","1.68","","","$","2.90","","","$","(1.22",")","","","(42","%)"],["NGLs (per bbl)","","10.80","","","","20.08","","","","(9.28",")","","","(46","%)"],["Crude oil (per bbl)","","62.43","","","","57.39","","","","5.04","","","","9","%"],["Total (per mcfe) (a)","","1.88","","","","3.17","","","","(1.29",")","","","(41","%)"]]
[[/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,"],["","","2023","","","2022"],["Average natural gas differentials below NYMEX","","$","(0.46",")","","$","(0.40",")"],["Realized gains on basis hedging","","$","0.05","","","$","0.11"]]
[[/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,"],["","","2022","","","Price Variance","","","Volume Variance","","","2023"],["Natural gas"],["Price (per mcf)","","$","6.24","","","$","(3.95",")","","$","\u2014","","","$","2.29"],["Production (Mmcf)","","","539,443","","","","\u2014","","","","(1,358",")","","","538,085"],["Natural gas sales","","$","3,364,111","","","$","(2,121,335",")","","$","(8,468",")","","$","1,234,308"]]
[[/GREPCENT_TABLE]]

41

[[GREPCENT_TABLE]]
[["","","Year Ended December 31,"],["","","2022","","","Price Variance","","","Volume Variance","","","2023"],["NGLs"],["Price (per bbl)","","$","35.96","","","$","(11.35",")","","$","\u2014","","","$","24.61"],["Production (Mbbls)","","","36,392","","","","\u2014","","","","1,548","","","","37,940"],["NGLs sales","","$","1,308,574","","","$","(430,434",")","","$","55,651","","","$","933,791"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["","","Year Ended December 31,"],["","","2022","","","Price Variance","","","Volume Variance","","","2023"],["Crude oil"],["Price (per bbl)","","$","87.79","","","$","(20.50",")","","$","\u2014","","","$","67.29"],["Production (Mbbls)","","","2,716","","","","\u2014","","","","(241",")","","","2,475"],["Crude oil sales","","$","238,407","","","$","(50,742",")","","$","(21,103",")","","$","166,562"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["","","Year Ended December 31,"],["","","2022","","","Price Variance","","","Volume Variance","","","2023"],["Consolidated"],["Price (per mcfe)","","$","6.34","","","$","(3.35",")","","$","\u2014","","","$","2.99"],["Production (Mmcfe)","","","774,089","","","","\u2014","","","","6,486","","","","780,575"],["Total natural gas, NGLs and oil sales","","$","4,911,092","","","$","(2,617,579",")","","$","41,148","","","$","2,334,661"]]
[[/GREPCENT_TABLE]]

Transportation, gathering, processing and compression expense was $1.1 billion in 2023 and $1.2 billion in 2022. These third-party costs are lower than the prior year due to lower fuel and lower electricity costs along with the impact of lower NGLs prices which results in lower processing costs. 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,"],["","2023","","","2022","","","Change","","","% Change"],["Transportation, gathering, processing and compression"],["Natural gas","$","588,970","","","$","677,316","","","$","(88,346",")","","","(13","%)"],["NGLs","","524,114","","","","565,614","","","","(41,500",")","","","(7","%)"],["Oil","","857","","","","11","","","","846","","","","7,691","%"],["Total","$","1,113,941","","","$","1,242,941","","","$","(129,000",")","","","(10","%)"],["Natural gas (per mcf)","$","1.09","","","$","1.26","","","$","(0.17",")","","","(13","%)"],["NGLs (per bbl)","$","13.81","","","$","15.54","","","$","(1.73",")","","","(11","%)"],["Oil (per bbl)","$","0.35","","","$","\u2014","","","$","0.35","","","","100","%"]]
[[/GREPCENT_TABLE]]

42

Derivative fair value income (loss) was a gain of $821.2 million in 2023 compared to a loss of $1.2 billion in 2022. 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, 2023, our commodity derivative contracts were recorded at their fair value, which was a net derivative asset of $424.4 million, an increase of $563.0 million from the $138.6 million net derivative liability recorded as of December 31, 2022. 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 $18.3 million as of December 31, 2023 compared to a net derivative asset of $521,000 as of December 31, 2022. The following table summarizes the impact of our commodity derivatives for the last two years (in thousands):

[[GREPCENT_TABLE]]
[["","","Year Ended December 31,"],["","","2023","","","2022"],["Derivative fair value income (loss) per consolidated statements of income","","$","821,154","","","$","(1,188,506",")"],["Non-cash fair value income (loss): (1)"],["Natural gas derivatives","","$","557,419","","","$","(2,392",")"],["Oil derivatives","","","23,301","","","","14,783"],["NGLs derivatives","","","\u2014","","","","2,931"],["Freight derivatives","","","\u2014","","","","(114",")"],["Contingent consideration","","","(13,080",")","","","(13,560",")"],["Total non-cash fair value income (loss) (1)","","$","567,640","","","$","1,648"],["Net cash receipt (payment) on derivative settlements:"],["Natural gas derivatives","","$","256,693","","","$","(1,119,940",")"],["Oil derivatives","","","(11,179",")","","","(82,546",")"],["NGLs derivatives","","","\u2014","","","","(12,168",")"],["Contingent consideration","","","8,000","","","","24,500"],["Total net cash receipt (payment)","","$","253,514","","","$","(1,190,154",")"]]
[[/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 income."]]
[[/GREPCENT_TABLE]]

Brokered natural gas, marketing and other revenue was $218.6 million in 2023 compared to $424.2 million in 2022. 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 2023 period includes $195.7 million of revenue from the sale of natural gas that is not related to our production (brokered) and $1.8 million of revenue from the sale of NGLs that is not related to our production, the receipt of $5.1 million in make-whole payments and $5.9 million of interest income. The 2022 period includes $408.6 million of revenue from the brokered sale of natural gas and $2.8 million of revenue from the sale of NGLs that is not related to our production and $2.5 million of interest income. These brokered revenues decreased compared to 2022 due to lower sales prices partially offset by higher brokered volumes.

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,"],["","2023","","","2022","","","Change","","","% Change"],["Direct operating expense","$","0.12","","","$","0.11","","","$","0.01","","","","9","%"],["Taxes other than income expense","","0.03","","","","0.05","","","","(0.02",")","","","(40","%)"],["General and administrative expense","","0.21","","","","0.22","","","","(0.01",")","","","(5","%)"],["Interest expense","","0.16","","","","0.21","","","","(0.05",")","","","(24","%)"],["Depletion, depreciation and amortization expense","","0.45","","","","0.46","","","","(0.01",")","","","(2","%)"]]
[[/GREPCENT_TABLE]]

43

Direct operating expense was $96.1 million in 2023 compared to $84.3 million in 2022. Direct operating expenses include normally recurring expenses to operate and produce our wells, non-recurring workover and repair-related expenses. On an absolute dollar basis, our direct operating expenses for 2023 increased 14% from the prior year primarily due to higher water hauling/handling costs, higher labor costs and higher workover costs. We incurred $4.5 million of workover costs in 2023 compared to $3.0 million of workover costs in 2022.

On a per mcfe basis, operating expense for 2023 increased $0.01, or 9% from the same period of 2022, with the increase due to higher 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,"],["","2023","","","2022","","","Change","","","% Change"],["Direct operating"],["Lease operating expense","$","0.11","","","$","0.11","","","$","\u2014","","","","\u2014","%"],["Workovers","","0.01","","","","\u2014","","","","0.01","","","","100","%"],["Stock-based compensation","","\u2014","","","","\u2014","","","","\u2014","","","","\u2014","%"],["Total direct operating expense","$","0.12","","","$","0.11","","","$","0.01","","","","9","%"]]
[[/GREPCENT_TABLE]]

Taxes other than income expense was $23.7 million in 2023 compared to $35.4 million in 2022. This expense category is primarily 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, 2023 includes a $21.8 million impact fee compared to $33.2 million in the year ended December 31, 2022, with the decrease primarily due to lower natural gas prices. This category also includes other taxes such as franchise, real estate and commercial activity taxes. The following table summarizes taxes other than income per mcfe for the last two years:

[[GREPCENT_TABLE]]
[["","Year Ended December 31,"],["","2023","","","2022","","","Change","","","% Change"],["Taxes other than income"],["Impact fee","$","0.03","","","$","0.04","","","$","(0.01",")","","","(25","%)"],["Other","","\u2014","","","","0.01","","","","(0.01",")","","","(100","%)"],["Total taxes other than income","$","0.03","","","$","0.05","","","$","(0.02",")","","","(40","%)"]]
[[/GREPCENT_TABLE]]

General and administrative expense was $164.7 million for 2023 compared to $168.1 million for 2022. The decrease in 2023, when compared to 2022, is primarily due to lower stock-based compensation and lower legal expenses partially offset by higher salaries and benefit costs. As of December 31, 2023, the number of general and administrative employees was the same when compared to December 31, 2022.

On a per mcfe basis, general and administrative expense for 2023 was 5% lower when compared to the same period of 2022 due to lower stock-based compensation. 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,"],["","2023","","","2022","","","Change","","","% Change"],["General and administrative"],["General and administrative","$","0.16","","","$","0.16","","","$","\u2014","","","","\u2014","%"],["Stock-based compensation","","0.05","","","","0.06","","","","(0.01",")","","","(17","%)"],["Total general and administrative expense","$","0.21","","","$","0.22","","","$","(0.01",")","","","(5","%)"]]
[[/GREPCENT_TABLE]]

44

Interest expense was $124.0 million for 2023 compared to $165.1 million for 2022. The following table summarizes interest expense per mcfe for the last two years:

[[GREPCENT_TABLE]]
[["","","Year Ended December 31,"],["","","2023","","","2022","","","Change","","","% Change"],["Bank credit facility","","$","0.01","","","$","0.01","","","$","\u2014","","","","\u2014","%"],["Senior notes","","","0.14","","","","0.19","","","","(0.05",")","","","(26","%)"],["Amortization of deferred financing costs and other","","","0.01","","","","0.01","","","","\u2014","","","","\u2014","%"],["Total interest expense","","$","0.16","","","$","0.21","","","$","(0.05",")","","","(24","%)"],["Average debt outstanding (in thousands)","","$","1,821,940","","","$","2,510,107","","","$","(688,167",")","","","(27","%)"],["Average interest rate (a)","","","6.5","%","","","6.25","%","","","0.25","%","","","4","%"]]
[[/GREPCENT_TABLE]]

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

On an absolute basis, the decrease in interest expense for 2023 from 2022 was primarily due to lower overall outstanding average debt balances. See Note 6 to our consolidated financial statements for additional information. Average debt outstanding on the bank credit facility for 2023 was $8.0 million compared to $48.4 million for 2022 and the weighted average interest rate on the bank credit facility was 8.4% for 2023 compared to 4.1% in 2022.

Depletion, depreciation and amortization ("DD&A") was $350.2 million in 2023 compared to $353.4 million in 2022. The decrease in 2023 when compared to 2022 is due to a 2% decrease in depletion rates. On a per mcfe basis, DD&A decreased to $0.45 in 2023 compared to $0.46 in 2022. Depletion expense, the largest component of DD&A, was $0.44 per mcfe in 2023 compared to $0.45 per mcfe in 2022. 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. The following table summarizes DD&A expenses per mcfe for the last two years:

[[GREPCENT_TABLE]]
[["","","Year Ended December 31,"],["","","2023","","","2022","","","Change","","","% Change"],["DD&A"],["Depletion and amortization","","$","0.44","","","$","0.45","","","$","(0.01",")","","","(2","%)"],["Accretion and other","","","0.01","","","","0.01","","","","\u2014","","","","\u2014","%"],["Total DD&A expenses","","$","0.45","","","$","0.46","","","$","(0.01",")","","","(2","%)"]]
[[/GREPCENT_TABLE]]

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 costs, deferred compensation plan and gain or loss on early extinguishment of debt. The following table details stock-based compensation that is allocated to functional expense categories for the last two years (in thousands):

[[GREPCENT_TABLE]]
[["","","2023","","","2022"],["Direct operating expense","","$","1,723","","","$","1,459"],["Brokered natural gas and marketing expense","","","2,095","","","","2,439"],["Exploration expense","","","1,250","","","","1,578"],["General and administrative expense","","","35,850","","","","42,023"],["Total stock-based compensation","","$","40,918","","","$","47,499"]]
[[/GREPCENT_TABLE]]

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

45

Brokered natural gas and marketing expense was $202.9 million in 2023 compared to $427.0 million in 2022. 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 decrease in these costs reflects lower purchase prices partially offset by higher purchased volumes. 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, 2023 (in thousands):

[[GREPCENT_TABLE]]
[["","2023","","","2022"],["Brokered natural gas and marketing"],["Brokered natural gas sales","$","195,656","","","$","408,584"],["Brokered NGLs sales","","1,834","","","","2,783"],["Interest income","","5,937","","","","2,538"],["Other marketing revenue and other income","","15,176","","","","10,312"],["Brokered natural gas purchases and transportation","","(191,659",")","","","(413,911",")"],["Brokered NGLs purchases","","(1,632",")","","","(2,808",")"],["Other marketing expense","","(9,593",")","","","(10,329",")"],["Net brokered natural gas and marketing margin","$","15,719","","","$","(2,831",")"]]
[[/GREPCENT_TABLE]]

Exploration expense was $26.5 million in 2023 compared to $26.8 million in 2022. Exploration expense in 2023 was lower when compared to the prior year with lower delay rentals partially offset by higher seismic and personnel costs. 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,"],["","2023","","","2022","","","Change","","","% Change"],["Exploration"],["Seismic","$","1,687","","","$","237","","","$","1,450","","","","612","%"],["Delay rentals and other","","17,644","","","","19,576","","","","(1,932",")","","","(10","%)"],["Personnel expense","","5,949","","","","5,381","","","","568","","","","11","%"],["Stock-based compensation expense","","1,250","","","","1,578","","","","(328",")","","","(21","%)"],["Total exploration expense","$","26,530","","","$","26,772","","","$","(242",")","","","(1","%)"]]
[[/GREPCENT_TABLE]]

Abandonment and impairment of unproved properties was $46.4 million in 2023 compared to $28.6 million in 2022. These costs increased when compared to the same period of 2022 due to higher 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.

Exit costs in 2023 were $99.9 million compared to $70.3 million in 2022. 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 the twelve months ended December 31, 2023, we recorded $41.9 million accretion expense related to these retained liabilities and in second quarter 2023, we recorded an adjustment of $37.8 million to increase this obligation for an increase in forecasted rates due to inflation. In addition, in fourth quarter 2023, we recorded an additional $18.0 million adjustment to increase the obligation for a change to our forecasted drilling plans of the buyer. In the twelve months ended December 31, 2022, we recorded $43.6 million accretion expense related to these retained liabilities and we recorded an adjustment of $24.8 million to increase this obligation for a change in forecasted drilling plans of the buyer and other adjustments. The following table details our exit costs for the last two years (in thousands):

[[GREPCENT_TABLE]]
[["","Year Ended December 31,"],["","2023","","","2022"],["Exit costs"],["Divestiture contract obligation (including accretion of discount)","$","99,595","","","$","69,758"],["Transportation contract capacity releases (including accretion of discount)","","345","","","","579"],["Total exit costs","$","99,940","","","$","70,337"]]
[[/GREPCENT_TABLE]]

46

Deferred compensation plan expense was $26.6 million in 2023 compared to $61.9 million in 2022. Our stock price increased to $30.44 at December 31, 2023 from $25.02 at December 31, 2022. 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. The deferred compensation plan held 1.5 million vested shares at December 31, 2023 compared to 5.3 million shares at December 31, 2022.

Gain (loss) on early extinguishment of debt was a gain of $438,000 in 2023 compared to a loss of $69.5 million in 2022. In second quarter 2023, we purchased on the open market $61.6 million principal amount of 4.875% senior notes due 2025 at a discount and recorded a gain of $438,000, net of transaction costs and the expensing of deferred financing costs on the repurchased debt. In first quarter 2022, we announced a call for the redemption of $850.0 million of our outstanding 9.25% senior notes due 2026 which were redeemed on February 1, 2022. The redemption price equaled 106.938% of par plus accrued and unpaid interest. We recognized a loss on early extinguishment of debt of $69.2 million.

Income tax expense was $229.2 million in 2023 compared to $230.5 million in 2022. Income tax expense was the same as the prior year with lower operating income offset by the impact of changes in our valuation allowances each year.

The following is a summary of income tax expense (in thousands):

[[GREPCENT_TABLE]]
[["","Year Ended December 31,"],["","2023","","","2022"],["Income tax expense"],["Current tax expense","$","1,547","","","$","14,688"],["Deferred income tax expense","","227,654","","","","215,772"],["Total income tax expense","$","229,201","","","$","230,460"],["Combined federal and state effective income tax rate","","20.8","%","","","16.3","%"]]
[[/GREPCENT_TABLE]]

See Note 4 to our consolidated financial statements for further detail.

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

Commodity prices are the most significant factor impacting our revenues, net income, operating cash flows, the amount of capital we invest in our business, payment of dividends and funding of share repurchases. Commodity prices have been and are expected to remain volatile. Our top priorities for using cash provided by operations are to fund our capital budget program, debt repayments and return capital to stockholders. We currently believe we have sufficient liquidity and capital resources to execute our business plan for the foreseeable future and across a wide range of commodity price environments.

Cash Flows

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

[[GREPCENT_TABLE]]
[["","","2023","","","2022"],["Sources of cash and cash equivalents"],["Operating activities","","$","977,892","","","$","1,864,744"],["Disposal of assets","","","872","","","","518"],["Borrowing on credit facility","","","185,000","","","","972,000"],["Issuance of new senior notes","","","\u2014","","","","500,000"],["Other","","","124,722","","","","72,713"],["Total sources of cash and cash equivalents","","$","1,288,486","","","$","3,409,975"],["Uses of cash and cash equivalents"],["Additions to natural gas and oil properties","","$","(571,819",")","","$","(456,505",")"],["Acreage purchases","","","(34,410",")","","","(30,885",")"],["Other property","","","(701",")","","","(682",")"],["Repayments on credit facility","","","(204,000",")","","","(953,000",")"],["Repayment of senior notes","","","(60,934",")","","","(1,659,422",")"],["Purchases of treasury stock","","","(19,042",")","","","(399,699",")"],["Dividends paid","","","(77,241",")","","","(38,638",")"],["Other","","","(108,572",")","","","(85,359",")"],["Total uses of cash and cash equivalents","","$","(1,076,719",")","","$","(3,624,190",")"]]
[[/GREPCENT_TABLE]]

47

Sources of Cash and Cash Equivalents

Cash flow from operating activities in 2023 was $977.9 million compared to $1.9 billion in 2022. Cash provided from operating activities is largely dependent upon commodity prices and production volumes, net of the effects of settlement of our derivative contracts. The decrease in cash provided from operating activities in 2023 from 2022 reflects significantly lower realized prices partially offset by the impact of a favorable change in working capital outflow (the timing of cash receipts and disbursements). As of December 31, 2023, we have hedged more than 45% of our projected total production for 2024 with more than 50% of our projected natural gas production hedged. 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 2023 was an outflow of $121.1 million compared to an outflow of $169.3 million for 2022.

Uses of Cash and Cash Equivalents

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 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]]
[["","","2023","","","2022"],["Appalachia","","$","571,607","","","$","462,134"],["Change in capital expenditure accrual for proved properties","","","1,204","","","","(4,116",")"],["Change in other non-cash capital expenditures","","","(992",")","","","(1,513",")"],["Additions to natural gas and oil properties","","$","571,819","","","$","456,505"]]
[[/GREPCENT_TABLE]]

Repayment of senior notes for 2023 includes the repurchase of $61.6 million principal of our 4.875% senior notes due 2025, at a discount.

Purchases of treasury stock for 2023 include the repurchase of 715,000 shares of common stock for a total of $19.0 million as part of our previously announced stock repurchase program.

Liquidity and Capital Resources

Our main sources of liquidity are cash, internally generated cash flow from operations, capital market transactions and our bank credit facility. At December 31, 2023, we had approximately $1.5 billion of liquidity consisting of cash on hand and availability under our bank credit facility.

Our liquidity requirements are supported by our cash on hand and our bank credit facility. We may draw on our bank credit facility to meet short-term cash requirements or issue debt or equity securities through the shelf registration discussed below as part of our longer-term liquidity and capital management. We believe our short-term and long-term liquidity is adequate to fund our current operations and our near-term and long-term funding requirements including our capital spending programs, repayment of debt maturities and dividends. Although we expect cash flows to be sufficient to fund our expected 2024 capital program, we may elect to use the bank credit facility or raise funds through new debt or equity offerings or from other sources of financing.

Bank Credit Facility

Our bank credit facility is secured by substantially all of our assets. In April 2022, we entered into an amended bank credit facility with a maturity date of April 14, 2027. As of December 31, 2023, 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 $1.5 billion. We also have undrawn letters of credit of $173.4 million as of December 31, 2023 which reduce the borrowing capacity under our bank credit facility.

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 2024. 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, 2023. See Note 6 to our consolidated financial statements for more information.

Capital Requirements

Our material cash requirements include the following contractual and other potential or expected obligations:

48

Capital Budget

Our approved capital budget for 2024 is $620 million to $670 million. The amount of our future capital expenditures will depend upon a number of factors including our cash flows from operations, investing and financing activities, infrastructure availability, supply and demand fundamentals and our ability to execute our development program. We periodically review our budget to assess changes in current and projected cash flows, debt requirements and other factors.

Long-Term Debt

As of December 31, 2023, we had $1.8 billion of total long-term debt outstanding. Our next significant long-term debt maturity is in the amount of $688.4 million due 2025. Anticipated cash annual interest payments related to our fixed-rate debt, based on the amount outstanding at December 31, 2023, is $23.8 million on our 4.75% senior notes, $33.6 million on our 4.875% senior notes and $49.5 million on our 8.25% senior notes.

Stock Repurchase Program

Our total remaining share repurchase authorization was approximately $1.1 billion at December 31, 2023.

Other Sources of Liquidity

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.

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, 2023, 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, 2023, we had a total of $173.4 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, 2023. In addition to the contractual obligations listed in the table below, our consolidated balance sheet at December 31, 2023 reflects accrued interest payable on our bank debt of $41,000, which is payable in first quarter 2024.

The following summarizes our contractual financial obligations at December 31, 2023 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"],["","2024","","","2025","","","2026","","","2027 and 2028","","","Thereafter","","","Total"],["Debt:"],["Bank debt due 2027 (a)","$","\u2014","","","$","\u2014","","","$","\u2014","","","$","\u2014","","","$","\u2014","","","$","\u2014"],["4.875% senior notes due 2025","","\u2014","","","","688,388","","","","\u2014","","","","\u2014","","","","\u2014","","","","688,388"],["8.25% senior notes due 2029","","\u2014","","","","\u2014","","","","\u2014","","","","\u2014","","","","600,000","","","","600,000"],["4.75% senior notes due 2030","","\u2014","","","","\u2014","","","","\u2014","","","","\u2014","","","","500,000","","","","500,000"],["Other obligations:","","","","","","","","","","","","","","","","","\u2014"],["Operating leases","","13,119","","","","7,921","","","","6,866","","","","2,698","","","","29","","","","30,633"],["Software licenses and other","","2,117","","","","576","","","","279","","","","16","","","","\u2014","","","","2,988"],["Derivative obligations (b)","","222","","","","107","","","","\u2014","","","","\u2014","","","","\u2014","","","","329"],["Transportation and gathering commitments (c)","","801,694","","","","730,907","","","","670,692","","","","616,260","","","","3,070,613","","","","5,890,166"],["Asset retirement obligation liability (d)","","2,395","","","","38","","","","\u2014","","","","\u2014","","","","114,996","","","","117,429"],["Total contractual obligations (e)","$","819,547","","","$","1,427,937","","","$","677,837","","","$","618,974","","","$","4,285,638","","","$","7,829,933"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["(a)","We had no outstanding balance as of the end of the year."],["(b)","Derivative obligations represent net liabilities determined in accordance with master netting arrangements for commodity derivatives that were valued as of December 31, 2023. 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, 2023. See Note 8 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 7 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]]

49

We have also entered into an additional agreement which modifies existing contracts that are included in the cash contractual obligation table above but is contingent on additional facility construction and is expected to begin in 2024 with a twelve-year term and adds to our ability to efficiently flow production volumes. The revised agreement covers volumes of 650,000 mcf per day but declines in the last five years of the contract ending at 300,000 mcf per day.

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 in 2020. 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 judgment and estimation. The actual settlement amount and timing may differ from our estimates. See also Note 13 and Note 14 to our consolidated financial statements. As of December 31, 2023, the carrying value of this obligation was $397.4 million (discounted) and is included in divestiture contract obligation in our consolidated balance sheets. As of December 31, 2023, our estimated settlement of this retained obligation based on a discounted value is as follows (in thousands):

[[GREPCENT_TABLE]]
[["","","Year Ended December 31,"],["2024","","$","86,762"],["2025","","","77,418"],["2026","","","61,805"],["2027","","","52,622"],["2028","","","48,116"],["Thereafter","","","70,727"],["","","$","397,450"]]
[[/GREPCENT_TABLE]]

Income Taxes

We are subject to income and non-income-based taxes under federal, state and local jurisdictions in which we operate. Historically, we have generated and carried forward net operating losses ("NOL") in amounts sufficient to offset all our taxable income at the federal level. To the extent we utilize all or substantially all of our federal NOL carryovers, we expect to begin to make federal income tax payments. In addition, the Inflation Reduction Act of 2022 could trigger minimum income taxes if we become subject to the corporate alternative minimum tax where we may have to make estimated federal income tax payments. We currently pay state income taxes in the Commonwealth of Pennsylvania. See Note 4 to our consolidated financial statements for more information.

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.

[[GREPCENT_TABLE]]
[["","","Year End December 31,"],["","","2023","","","2022"],["","","(Mmcfe)"],["Proved Reserves:"],["Beginning of year","","","18,077,656","","","","17,775,484"],["Reserve revisions","","","608,784","","","","(591,983",")"],["Reserve extensions, discoveries and additions","","","207,260","","","","1,668,244"],["Production","","","(780,575",")","","","(774,089",")"],["End of year","","","18,113,125","","","","18,077,656"],["Proved Developed Reserves:"],["Beginning of year","","","10,933,180","","","","10,417,887"],["End of year","","","11,535,852","","","","10,933,180"]]
[[/GREPCENT_TABLE]]

Our proved reserves at year-end 2023 were 18.1 Tcfe which were slightly higher than year-end 2022. Natural gas comprised approximately 64% of our proved reserves at year-end 2023.

Reserve Revisions and Additions. Revisions of previous estimates of a positive 608.8 Bcfe includes a positive revision of 280.2 Bcfe for previously undeveloped properties reclassified from non-proved properties due to their addition to our five-year development plan and positive performance revisions of 701.4 Bcfe due to improved well performance and longer lateral lengths partially offset by negative pricing revisions and 370.6 Bcfe reclassified to unproved for previously planned wells not to be drilled within the original five-year development horizon. We added 207.3 Bcfe of proved reserves from drilling activities and evaluation of proved areas in

50

Pennsylvania. Our ethane reserves are intended to match volumes delivered under our existing long-term, extendable contracts along with meeting pipeline specifications.

During 2022, we added 1.7 Tcfe of proved reserves from drilling activities and evaluation of proved areas in Pennsylvania. Approximately 77% of the 2022 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 592.0 Bcfe includes 1.4 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, positive performance revisions of 72.8 Bcfe and 716.2 Bcfe for previously proved undeveloped properties as they were added back to our five-year development plan. Wells reclassified to unproved during the year are the result of the out-performance of existing wells which resulted in a higher utilization of in-field gathering capacity and a reallocation of capital due to the drilling of longer laterals on existing locations.

Future Net Cash Flows. At December 31, 2023, the present value (discounted at 10%) of estimated future net cash flows from our proved reserves was $7.9 billion. The present value of our estimated future net cash flows at December 31, 2022 was $29.6 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, 2023, the after-tax present value of estimated future net cash flows from our proved reserves was $6.8 billion compared to $24.5 billion at December 31, 2022.

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.

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, 2023, our delivery commitments through 2037 were as follows:

[[GREPCENT_TABLE]]
[["Year Ending December 31,","","Natural Gas (mmbtu per day)","","Ethane and Propane (bbls per day)"],["2024","","302,404","","70,000"],["2025","","282,493","","54,932"],["2026","","200,548","","50,000"],["2027","","100,000","","46,233"],["2028","","100,000","","45,000"],["2029","","100,000","","33,444"],["2030","","-","","30,000"],["2031","","-","","16,575"],["2032 - 2037","","-","","10,000 (each year)"]]
[[/GREPCENT_TABLE]]

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. We also regularly provide letters of credit in the normal course of business under certain contracts that may be drawn if we fail to perform under those contracts.

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.

51

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 96% of our reserves in both 2023 and 2022. Historical variances between our reserve estimates and the aggregate estimates of our consultants have been approximately 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, 2023 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, 2023, it could have an adverse effect on our estimates of 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, 2023, we estimate that a 1% change in proved reserves would increase or decrease 2024 depletion expense

52

by approximately $3.0 million (based on current production estimates). We currently expect our DD&A rate to be approximately $0.44 per mcfe in 2024. 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 15 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 9 to the consolidated financial statements for disclosures regarding our fair value measurements.

The need to test long-lived assets for impairment can be based on several indicators, including reductions 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. Valuation methods used to measure fair value may require significant management judgement and estimates to derive the inputs necessary to determine fair value.

Whenever changes in facts and circumstances indicate that the carrying value of our long-lived assets may not be recoverable, we perform an impairment evaluation. For purposes of this 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. As of December 31, 2023, our estimated undiscounted cash flows relating to our long-lived assets significantly exceeded their carrying values.

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. We base our fair value estimates on projected financial information which we believe to be reasonably likely to occur. An estimate of the sensitivity to changes in assumptions in our undiscounted cash flow calculations is not practicable, given the numerous assumptions (e.g. reserves, pace and timing of development plans, commodity prices, capital expenditures, operating costs, drilling and development costs, inflation and discount rates) that can materially affect our estimates. Unfavorable adjustments to some of the above listed assumptions would likely

53

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.

We record all derivative instruments at fair value. Fair value measurements are based on observable market-based inputs that are corroborated by market data and are discussed more fully in Note 8 to our consolidated financial statements and in Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

Exit Cost Estimates

Our consolidated balance sheets include accrued exit cost obligations related to retained gathering, processing and transportation contracts associated with divestiture of our North Louisiana assets during 2020. Inherent in the initial fair value calculation of these exit costs were 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 believed to be reasonable and likely to occur. We have continued to refine our forecast of the buyer's development plans since the divestiture. Changes in other assumptions, such as the estimate of production volumes flowing to certain 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 $9.1 million. If the forecasted inflation rates were to increase or decrease in the amount of 1%, the difference in the liability would be $9.4 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 13 and Note 14 to our consolidated financial statements for a further discussion of these costs.

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, new legislation 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. 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 deferred tax assets may result in a reversal of all or a portion of the valuation allowance. See Note 4 to our consolidated financial statements for additional information.

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.

54

Accounting Standards Not Yet Adopted

None that are expected to have a material impact.

55