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Item 7. Management’s Discussion and Analysis

2024-02-14 compared with 2023-02-16 · 114 added, 225 removed, 243 unchanged (58% of the section changed)

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Consolidated Results of Operations

Net income attributable to EQT Corporation for 2022 was $1,771 million, $4.38 per diluted share, compared to net loss attributable to EQT Corporation for 2021 of $1,143 million, $3.54 per diluted share.

The change was attributable primarily to increased sales of natural gas, NGLs and oil, partly offset by income tax expense, greater loss on derivatives, the impairment of our contract asset (discussed in Note 5 to the Consolidated Financial Statements), increased transportation and processing expense and increased loss on debt extinguishment.

Net loss attributable to EQT Corporation for 2021 was $1,143 million, $3.54 per diluted share, compared to net loss attributable to EQT Corporation for 2020 of $959 million, $3.68 per diluted share.

The change was attributable primarily to the loss on derivatives, increased depreciation and depletion, increased transportation and processing and the gain on the Equitrans Share Exchange (defined and discussed in Note 5 to the Consolidated Financial Statements) recognized in 2020, partly offset by increased sales of natural gas, NGLs and oil, the income from investments, higher income tax benefit and the gain on sale/exchange of long-lived assets.

Results of operations for 2022 and for the period beginning July 21, 2021 and ending December 31, 2021 include the results of our operation of assets acquired in the Alta Acquisition.

See Note 6 to the Consolidated Financial Statements for further discussion.

Net income attributable to EQT Corporation for 2023 was $1,735 million, $4.22 per diluted share, compared to $1,771 million, $4.38 per diluted share, for 2022.

The decrease was attributable primarily to decreased sales of natural gas, NGLs and oil, partly offset by a gain on derivatives in 2023 compared to a loss on derivatives in 2022, impairment of the contract asset (discussed in Note 5 to the Consolidated Financial Statements) in 2022, decreased income tax expense and a loss on debt extinguishment in 2022.

See Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations" included in our Annual Report on Form 10-K for the year ended December 31, 2022, which is incorporated herein by reference, for discussion and analysis of consolidated results of operations for the year ended December 31, 2021.

Results of operations for the period beginning August 22, 2023 through December 31, 2023 include the results of our operation of assets acquired in the Tug Hill and XcL Midstream Acquisition.

See Note 6 to the Consolidated Financial Statements for further discussion of the Tug Hill and XcL Midstream Acquisition.

See "Sales Volume and Revenues" and "Operating Expenses" for discussions of items affecting operating income and "Other Income Statement Items" for a discussion of other income statement items.

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Trends and Uncertainties

Our sales volume and operating expenses for 2022 were negatively impacted by fewer wells turned-in-line and adjustments to our planned development schedule as a result of third-party supply chain constraints.

Strong underlying well performance and field optimization helped mitigate the impacts to 2022 sales volume;

however, supply chain constraints may continue to impact our future sales volume, operating revenues and expenses, per unit metrics and capital expenditures.

The annual inflation rate in the United States was particularly high during 2022, and many analysts anticipate inflation will remain elevated through 2023.

Our sales volume and operating expenses on a per Mcfe basis during the first half of 2023 were negatively impacted by fewer wells turned-in-line during 2022 compared to our 2022 planned development schedule due to third-party supply chain constraints.

In addition, as a result of third-party supply chain constraints in 2022, we shifted the planned development of approximately 30 wells from 2022 to 2023 (the Rescheduled Wells).

All of the Rescheduled Wells were completed and turned-to-sales as of July 2023, resulting in our third quarter 2023 sales volumes returning to our normalized level of production;

however, our sales volume during the second half of 2023 was negatively impacted by approximately 13 Bcfe of curtailments (inclusive of non-operated wells in which we have a working interest) principally in response to lower natural gas prices in the Appalachian Basin.

Future supply chain constraints or declines in natural gas prices may result in adjustments to our 2024 planned development schedule or the development schedule of non-operated wells in which we have a working interest.

Further, we cannot control or otherwise influence the development schedule of non-operated wells in which we have a working interest.

Adjustments to our 2024 planned development schedule or the development schedule of non-operated wells in which we have a working interest, including due to declines in natural gas prices, the pace of well completions, access to sand and water to conduct drilling operations, access to sufficient pipeline takeaway capacity, unscheduled downtime at processing facilities or otherwise, could impact our future sales volume, operating revenues and expenses, per unit metrics and capital expenditures.

The annual inflation rate in the United States increased rapidly during 2022, and, although the inflation rate decreased through 2023, it still remains elevated compared to the rate of inflation over the prior five years.

Inflationary pressures have multiple impacts on our business, including increasing our operating expenses and our cost of capital.

Furthermore, certain of our commitments for demand charges under our existing long-term contracts and processing capacity are subject to consumer price index adjustments.

While the prices for certain of the raw materials and services we use in our operations have generally decreased from the peak prices experienced during 2022, we will not fully realize the benefit of such reduced prices until we enter into new contracts for such materials and services, and inflationary pressures may cause prices to fluctuate.

Additionally, certain of our commitments for demand charges under our existing long-term contracts and processing capacity are subject to consumer price index adjustments.

Although we believe our scale and supply chain contracting strategy of using multi-year sand and frac crew contracts allows us to maximize capital and operating efficiencies, future increases in the inflation rate will negatively impact our long-term contracts with consumer price index adjustments.

Additionally, while the prices for natural gas, NGLs and oil have historically been volatile, price volatility was especially pronounced during 2022.

The daily spot prices for NYMEX Henry Hub natural gas ranged from a high of $9.85 per MMBtu to a low of $3.46 per MMBtu between the period from January 1, 2022 through December 31, 2022, and the daily spot prices for NYMEX West Texas Intermediate crude oil ranged from a high of $123.64 per barrel to a low of $71.05 per barrel during the same period.

We expect commodity price volatility to continue or increase throughout 2023 due to rising macroeconomic uncertainty and geopolitical tensions, including the Russian invasion of Ukraine, which began in February 2022 and has put upward pressure on natural gas and oil prices.

Our revenue, profitability, rate of growth, liquidity and financial position will continue to be impacted in the future by the market prices for natural gas and, to a lesser extent, NGLs and oil.

While the prices for natural gas, NGLs and oil have historically been volatile, price volatility was especially pronounced during 2022, with natural gas prices peaking in August 2022, then steadily declining into the first half of 2023.

The second half of 2023 saw moderate increases in natural gas prices;

however, on average, prices in 2023 remained lower than in 2022.

We expect commodity prices to be volatile throughout 2024 due to macroeconomic uncertainty and geopolitical tensions, including developments pertaining to Russia's invasion of Ukraine and conflicts in the Middle East.

Our revenue, profitability, liquidity and financial position will continue to be impacted in the future by the market prices for natural gas and, to a lesser extent, NGLs and oil.

Additionally, after several years of delays, in the third quarter of 2023, Equitrans Midstream resumed forward construction of the Mountain Valley Pipeline following the approval of federal legislation ratifying and approving all permits and authorizations necessary for the construction and initial operation of the project.

The fee structure and various conditions precedent specified in certain of our agreements with Equitrans Midstream, including but not limited to the Consolidated GGA, are tied to the date on which the Mountain Valley Pipeline is placed in service.

As a result, the timing of the date on which the Mountain Valley Pipeline is ultimately placed in service, which is outside of our control, could impact our operating results during 2024, including our operating expenses and per unit metrics, average differential and any payments required to settle the Henry Hub Cash Bonus (defined and described in Note 3 to the Consolidated Financial Statements), if required.

Average Realized Price Reconciliation

The following table presents detailed natural gas and liquids operational information to assist in the understanding of our consolidated operations, including the calculation of our average realized price ($/Mcfe), which is based on adjusted operating

revenues, a non-GAAP supplemental financial measure.

Adjusted operating revenues is presented because it is an important measure we use to evaluate period-to-period comparisons of earnings trends.

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Years Ended December 31,

2022 2021 2020

(Thousands, unless otherwise noted)

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We use adjusted operating revenues to evaluate earnings trends because, as a result of the measure's exclusion of the often-volatile changes in the fair value of derivative instruments prior to settlement, the measure reflects only the impact of settled derivative contracts.

Net marketing services and other consists of the costs of, and recoveries on, pipeline capacity releases, revenues for gathering services provided to third parties and other revenues.

Net marketing services and other consists of the costs of, and recoveries on, pipeline capacity releases, revenues for gathering and processing services provided to third parties and other revenues.

Because we consider net marketing services and other to be unrelated to our natural gas and liquids production activities, adjusted operating revenues excludes net marketing services and other.

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Years Ended December 31,

2022 2021 2020

(Thousands, unless otherwise noted)

Total operating revenues $ 6,908,923 $ 7,497,689

Add (deduct):

Loss (gain) on derivatives 4,642,932 3,775,042 (400,214)

Net cash settlements (paid) received on derivatives (5,927,698) (2,091,003) 897,190

Premiums (paid) received for derivatives that settled during the period (27,587) (67,809) 1,630

(Deduct) add:

(Gain) loss on derivatives (1,838,941) 4,642,932

Net cash settlements received (paid) on derivatives 900,650 (5,927,698)

Premiums paid for derivatives that settled during the period (322,869) (27,587)

Net marketing services and other (25,214) (26,453)

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(Thousands, unless otherwise noted)

Sales volume by shale (MMcfe):

1,809,049 1,684,673 124,376 7.4

Ohio Utica 123,517 163,775 (40,258) (24.6)

Other 7,477 9,369 (1,892) (20.2)

Total sales volume 1,940,043 1,857,817 82,226 4.4

Sales volume (MMcfe) 2,016,273 1,940,043 76,230 3.9

Average daily sales volume (MMcfe/d) 5,524 5,315 209 3.9

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Sales of natural gas, NGLs and oil $ 5,044,768 $ 12,114,168 $ (7,069,400) (58.4)

Loss on derivatives (4,642,932) (3,775,042) (867,890) 23.0

Gain (loss) on derivatives 1,838,941 (4,642,932) 6,481,873 (139.6)

Net marketing services and other 25,214 26,453 (1,239) (4.7)

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Sales of natural gas, NGLs and oil.

Sales of natural gas, NGLs and oil increased for 2022 compared to 2021 due to a higher average realized price and increased sales volume.

Average realized price for 2022 compared to 2021 increased due to higher NYMEX prices and higher liquids prices, partly offset by unfavorable cash settled derivatives and unfavorable differential.

For 2022 and 2021, we paid $5,927.7 million and $2,091.0 million, respectively, of net cash settlements on derivatives, which are included in average realized price but may not be included in operating revenues.

Sales volume increased primarily as a result of sales volume increases from the assets acquired in the Alta Acquisition, partly offset by natural decline of producing wells and fewer wells turned-in-line.

Sales volume for 2022 was negatively impacted by fewer wells turned-in-line as a result of third-party supply chain constraints.

Supply chain constraints and inflationary pressures may continue to impact our future operating revenues.

The assets which we intend to acquire in the pending Tug Hill and XcL Midstream Acquisition, which is subject to regulatory approvals, are currently producing approximately 800 MMcfe per day of sales volume, 20% of which is liquids sales volume.

Loss on derivatives.

For 2022 and 2021, we recognized a loss on derivatives of $4,642.9 million and $3,775.0 million, respectively, related primarily to decreases in the fair market value of our NYMEX swaps and options due to increases in NYMEX forward prices.

Net marketing services and other.

Net marketing services and other decreased for 2022 compared to 2021 due primarily to a decrease in the liquids uplift realized on gas purchased at the wellhead from other operators, partly offset by an increase in third-party gathering revenues recognized on the midstream assets acquired in the Alta Acquisition.

Sales of natural gas, NGLs and oil decreased for 2023 compared to 2022 due to lower average realized price, partly offset by increased sales volume.

Average realized price decreased for 2023 compared to 2022 due to lower NYMEX and liquids prices, partly offset by favorable cash settled derivatives and favorable differential.

The following table presents the composition of net cash settlements that we received (paid) on derivatives.

Years Ended December 31,

2021 2020 Change % Change

(Thousands, unless otherwise noted)

Sales volume by shale (MMcfe):

1,684,673 1,314,801 369,872 28.1

Ohio Utica 163,775 177,864 (14,089) (7.9)

Other 9,369 5,127 4,242 82.7

Total sales volume 1,857,817 1,497,792 360,025 24.0

Average daily sales volume (MMcfe/d) 5,090 4,092 998 24.4

Operating revenues:

Sales of natural gas, NGLs and oil $ 6,804,020 $ 2,650,299 $ 4,153,721 156.7

(Loss) gain on derivatives (3,775,042) 400,214 (4,175,256) (1,043.3)

Net marketing services and other 35,685 8,330 27,355 328.4

Total operating revenues $ 3,064,663 $ 3,058,843 $ 5,820 0.2

Sales of natural gas, NGLs and oil.

Sales of natural gas, NGLs and oil increased for 2021 compared to 2020 due to increased sales volume and a higher average realized price.

Sales volume increased primarily as a result of sales volume increases of 170 Bcfe from the assets acquired in the Alta Acquisition, sales volume increases of 127 Bcfe from the assets acquired in the Chevron Acquisition (defined in Note 6 to the Consolidated Financial Statements), prior year sales volume decreases of 46 Bcfe from the 2020 Strategic Production Curtailments and sales volume increases as a result of the Reliance Asset Acquisition (defined in Note 6 to the Consolidated Financial Statements) and from wells turned in-line during 2021, partly offset by sales volume decreases of 9 Bcfe from the 2020 Divestiture (defined in Note 8 to the Consolidated Financial Statements).

The 2020 Strategic Production Curtailments refers to our strategic decisions to temporarily curtail certain 2020 production.

In May 2020, we temporarily curtailed approximately 1.4 Bcf per day of gross production, equivalent to approximately 1.0 Bcf per day of net production.

In July 2020, we began a moderated approach to bring back on-line the curtailed production.

In September 2020, we curtailed approximately 0.6 Bcf per day of gross production, equivalent to approximately 0.4 Bcf per day of net production.

In October 2020, we began a phased approach to bring back on-line the curtailed production, which was completed in November 2020.

Average realized price increased due to higher NYMEX prices and higher liquids prices, partly offset by lower cash settled derivatives and unfavorable differential.

For 2021 and 2020, we paid $2,091.0 million and received $897.2 million, respectively, of net cash settlements on derivatives, which are included in average realized price but may not be included in operating revenues.

(Loss) gain on derivatives.

For 2021 and 2020, we recognized a loss of $3,775.0 million and a gain of $400.2 million, respectively, on derivatives.

The loss for 2021 was related primarily to decreases in the fair market value of our NYMEX swaps and options due to increases in NYMEX forward prices.

The gain for 2020 was related primarily to increases in the fair market value of our NYMEX swaps and options due to decreases in NYMEX forward prices.

Net marketing services and other.

Net marketing services and other increased for 2021 compared to 2020 due primarily to the liquids uplift realized on gas purchased at the wellhead from other operators and third-party gathering revenues recognized on the midstream assets acquired in the Alta Acquisition.

Net cash settlements received (paid) on NYMEX natural gas hedge positions $ 976,432 $ (5,855,959)

Net cash settlements paid on basis and liquids hedge positions (75,782) (71,739)

Net cash settlements received (paid) on derivatives $ 900,650 $ (5,927,698)

Net cash settlements received (paid) on derivatives are included in average realized price but may not be included in operating revenues.

For 2023 and 2022, we paid premiums for derivatives that settled during the period of $322.9 million and $27.6 million, respectively.

Sales volume increased for 2023 compared to 2022 due to sales volume increases of 90 Bcfe from the assets acquired in the Tug Hill and XcL Midstream Acquisition, partly offset by sales volume decreases from the natural decline of producing wells and fewer wells turned-in-line during 2022 as a result of third-party supply chain constraints and delays in the development schedule of certain non-operated wells in which we have a working interest.

Gain (loss) on derivatives.

For 2023, we recognized a gain on derivatives of $1,838.9 million related primarily to increases in the fair market value of our NYMEX swaps and options due to decreases in NYMEX forward prices, partly offset by a loss on the derivative liability related to the Henry Hub Cash Bonus.

For 2022, we recognized a loss on derivatives of $4,642.9 million related primarily to decreases in the fair market value of our NYMEX swaps and options due to increases in NYMEX forward prices, partly offset by a gain on the derivative liability related to the Henry Hub Cash Bonus.

Operating Expenses

19 unchanged sentences

Production taxes 0.05 0.07 (0.02) (28.6)

Exploration — 0.01 (0.01) (100.0)

Selling, general and administrative 0.12 0.13 (0.01) (7.7)

Production depletion 0.84 0.85 (0.01) (1.2)

Gathering expense increased on an absolute basis for 2022 compared to 2021 due primarily to increased sales volume from the assets acquired in the Alta Acquisition and higher gathering rates on certain contracts indexed to price, partly offset by lower expense as a result of less utilization of lower overrun rates as part of the Consolidated GGA (defined and discussed in Note 5 to the Consolidated Financial Statements) due to the natural decline of producing wells and fewer wells turned-in-line.

Gathering expense increased on a per Mcfe basis for 2022 compared to 2021 due primarily to higher gathering rates on certain contracts indexed to price and less utilization of lower overrun rates as part of the Consolidated GGA due to the natural decline of producing wells and fewer wells turned-in-line, partly offset by the lower gathering rate structure on the assets acquired in the Alta Acquisition.

Gathering expense decreased on an absolute basis for 2023 compared to 2022 due primarily to lower gathering rates on certain contracts indexed to price.

Gathering expense decreased on a per Mcfe basis for 2023 compared to 2022 due primarily to lower gathering rates on certain contracts indexed to price, which decreased in 2023, as well as the impact of the gathering assets acquired in the Tug Hill and XcL Midstream Acquisition, which are wholly owned by us and, therefore, reduce our gathering cost structure.

Transmission.

Transmission expense increased on an absolute and per Mcfe basis for 2022 compared to 2021 due primarily to higher rates on and lower credits received from the Texas Eastern Transmission Pipeline, additional capacity acquired in the Alta Acquisition and additional capacity acquired on the Rockies Express Pipeline in September 2021.

Processing expense increased on an absolute basis for 2022 compared to 2021 due to increased volumes that require processing as a result of increased development of liquids-rich areas.

LOE increased on an absolute and per Mcfe basis for 2022 compared to 2021 due primarily to additional lease operating costs as a result of the Alta Acquisition and higher salt water disposal costs.

Transmission expense increased on an absolute and per Mcfe basis for 2023 compared to 2022 due primarily to additional capacity acquired, partly offset by increased credits received from the Texas Eastern Transmission Pipeline.

Processing expense increased on an absolute and per Mcfe basis for 2023 compared to 2022 due primarily to processing expenses for the liquids-rich assets acquired in the Tug Hill and XcL Midstream Acquisition as well as inflation of third-party-contracted processing rates.

LOE increased on an absolute basis for 2023 compared to 2022 due primarily to increased LOE from the assets acquired in the Tug Hill and XcL Midstream Acquisition, partly offset by lower saltwater disposal costs and increased recycling.

Saltwater disposal costs and recycle rates were favorably impacted by increased use of our internally developed produced water gathering and storage system, which was placed in service during the fourth quarter of 2022.

Production taxes.

Production taxes increased on an absolute and per Mcfe basis for 2022 compared to 2021 due to increased West Virginia severance taxes, which resulted primarily from higher prices, and increased Pennsylvania impact fees, which resulted from additional wells spud in 2022, including those acquired in the Alta Acquisition, higher prices and inflation.

Exploration expense decreased on an absolute and per Mcfe basis for 2022 compared to 2021 due primarily to our purchase of seismic data in 2021 following the completion of the Alta Acquisition.

Production taxes decreased on an absolute and per Mcfe basis for 2023 compared to 2022 due to lower West Virginia severance taxes due to lower TETCO M2 price and lower Pennsylvania impact fees due to lower NYMEX price, partly offset by higher West Virginia property taxes due to assets acquired in the Tug Hill and XcL Midstream Acquisition and higher rates.

Selling, general and administrative.

Selling, general and administrative expense increased on an absolute and per Mcfe basis for 2022 compared to 2021 due primarily to higher long-term incentive compensation costs as a result of changes in the fair value of awards and increased labor costs driven by an increase in the number of our total permanent employees.

Selling, general and administrative expense decreased on an absolute and per Mcfe basis for 2023 compared to 2022 due primarily to lower long-term incentive compensation costs as a result of decreases in awards outstanding and changes in the fair value of awards.

Long-term incentive compensation may fluctuate with changes in our stock price and performance conditions.

Depreciation and depletion.

Production depletion expense decreased on an absolute and per Mcfe basis for 2022 compared to 2021 due to a lower annual depletion rate.

(Gain) loss/impairment on sale/exchange of long-lived assets .

During 2022 and 2021, we recognized a gain on sale/exchange of long-lived assets of $8.4 million and $21.1 million, respectively, related primarily to changes in the fair value of the Contingent Consideration (defined and discussed in Note 8 to the Consolidated Financial Statements) from the 2020 Divestiture.

Impairment of contract and other assets.

During 2022, we recognized impairment of our contract asset of $214.2 million as discussed in Note 5 to the Consolidated Financial Statements.

Impairment and expiration of leases.

During 2022 and 2021, we recognized impairment and expiration of leases of $176.6 million and $311.8 million, respectively, related to impairment and expiration of leases that we no longer expect to develop based on our development plan.

Other operating expenses.

Other operating expenses for 2022 of $57.3 million were attributable primarily to changes in legal and environmental reserves including settlements as well as transaction costs associated with the Tug Hill and XcL Midstream Acquisition.

Other operating expenses for 2021 of $70.1 million were attributable primarily to transaction costs associated with the Alta Acquisition and Chevron Acquisition.

See Note 1 to the Consolidated Financial Statements for a summary of other operating expenses.

Years Ended December 31,

2021 2020 Change % Change

(Thousands, unless otherwise noted)

Operating expenses:

Gathering $ 1,228,153 $ 1,068,590 $ 159,563 14.9

Transmission 525,811 506,668 19,143 3.8

Processing 188,201 135,476 52,725 38.9

LOE 126,640 109,027 17,613 16.2

Production taxes 98,639 46,376 52,263 112.7

Exploration 24,403 5,484 18,919 345.0

Selling, general and administrative 196,315 174,769 21,546 12.3

Production depletion $ 1,658,113 $ 1,375,542 $ 282,571 20.5

Other depreciation and depletion 18,589 17,923 666 3.7

Total depreciation and depletion $ 1,676,702 $ 1,393,465 $ 283,237 20.3

Per Unit ($/Mcfe):

Gathering $ 0.66 $ 0.71 $ (0.05) (7.0)

Transmission 0.28 0.34 (0.06) (17.6)

Processing 0.10 0.09 0.01 11.1

LOE 0.07 0.07 — —

Production taxes 0.05 0.03 0.02 66.7

Exploration 0.01 — 0.01 100.0

Selling, general and administrative 0.11 0.12 (0.01) (8.3)

Production depletion 0.89 0.92 (0.03) (3.3)

Gathering expense increased on an absolute basis for 2021 compared to 2020 due to increased sales volume.

Gathering expense decreased on a per Mcfe basis for 2021 compared to 2020 due primarily to the lower gathering rate structures on the assets acquired in the Chevron Acquisition and Alta Acquisition and increased sales volume, which resulted in our utilization of lower overrun rates as part of the Consolidated GGA (defined and discussed in Note 5 to the Consolidated Financial Statements).

Transmission .

Transmission expense increased on an absolute basis for 2021 compared to 2020 due primarily to additional capacity acquired as part of the Alta Acquisition.

Transmission expense decreased on a per Mcfe basis for 2021 compared to 2020 due primarily to increased sales volume from the Chevron Acquisition and Alta Acquisition, which have a lower average transmission expense per Mcfe when compared to our historical transmission portfolio.

Processing expense increased on an absolute and per Mcfe basis for 2021 compared to 2020 due to increased liquid sales volume as a result of increased development of liquids-rich areas and increased processed volume from the Chevron Acquisition.

LOE increased on an absolute basis for 2021 compared to 2020 due primarily to additional lease operating costs as a result of the Alta Acquisition and Chevron Acquisition.

Production taxes .

Production taxes increased on an absolute and per Mcfe basis for 2021 compared to 2020 due to increased West Virginia severance taxes, which resulted primarily from higher prices, and increased Pennsylvania impact fees, which resulted from higher prices and additional wells acquired in the Alta Acquisition and Chevron Acquisition.

Exploration .

Exploration expense increased on an absolute and per Mcfe basis for 2021 compared to 2020 due primarily to our purchase of seismic data following the completion of the Alta Acquisition.

Selling, general and administrative .

Selling, general and administrative expense increased on an absolute basis for 2021 compared to 2020 due primarily to higher long-term incentive compensation costs as a result of changes in the fair value of

awards as well as higher litigation expense.

Selling, general and administrative expense decreased on a per Mcfe basis for 2021 compared to 2020 due primarily to increased sales volumes and nominal incremental selling, general and administrative spend with respect to the Alta Acquisition and Chevron Acquisition.

Depreciation and depletion .

Production depletion expense increased on an absolute basis for 2023 compared to 2022 due to increased sales volume, partly offset by a lower annual depletion rate.

Production depletion expense decreased on a per Mcfe basis for 2021 compared to 2020 due to a lower annual depletion rate.

Amortization of intangible assets .

Amortization of intangible assets for 2020 was $26.0 million.

Our intangible assets were fully amortized in November 2020.

(Gain) loss/impairment on sale/exchange of long-lived assets .

During 2021, we recognized a gain on sale/exchange of long-lived assets of $21.1 million related primarily to changes in the fair value of the Contingent Consideration from the 2020 Divestiture.

During 2020, we recognized a loss on sale/exchange of long-lived assets of $100.7 million, of which $61.6 million related to the 2020 Asset Exchange Transactions (defined and discussed in Note 7 to the Consolidated Financial Statements) and $39.1 million related to asset sales, including the 2020 Divestiture.

Impairment of intangible and other assets .

During the fourth quarter of 2020, we recognized impairment of $34.7 million, of which $22.8 million related to our assessment that the fair values of certain of our right-of-use lease assets were less than their carrying values and $11.9 million related to impairments of certain of our non-operating receivables as a result of expected credit losses.

Loss (gain) on sale/exchange of long-lived assets .

During 2023, we recognized a loss on sale/exchange of long-lived assets of $17.4 million related to acreage trade agreements where the carrying value of the acres traded exceeded the fair value of the acres received.

Impairment of contract asset.

During 2022, we recognized impairment of our contract asset of $214.2 million.

See Note 5 to the Consolidated Financial Statements.

Impairment and expiration of leases.

During 2021 and 2020, we recognized impairment and expiration of leases of $311.8 million and $306.7 million, respectively, related to impairment and expiration of leases that we no longer expect to develop based on our development strategy.

During 2023 and 2022, we recognized impairment and expiration of leases of $109.4 million and $176.6 million, respectively, related primarily to leases that we no longer expect to extend or develop prior to their expiration based on our development plan.

Other operating expenses.

Other operating expenses for 2021 of $70.1 million were attributable primarily to transaction costs associated with the Alta Acquisition and Chevron Acquisition.

Other operating expenses for 2020 of $28.5 million were attributable primarily to transactions, changes in legal reserves, including settlements, and reorganization.

Other operating expenses increased for 2023 compared to 2022 due primarily to transaction costs associated with the Tug Hill and XcL Midstream Acquisition, partly offset by decreased legal and environmental reserves, including from settlements.

See Note 1 to the Consolidated Financial Statements for a summary of other operating expenses.

Other Income Statement Items

Gain on Equitrans Share Exchange.

During the first quarter of 2020, we recognized a gain on the Equitrans Share Exchange of $187.2 million.

See Note 5 to the Consolidated Financial Statements.

Loss (income) from investments.

For 2022, we recognized a loss from investments due to a loss on the sale of our investment in Equitrans Midstream, which resulted from a decrease in Equitrans Midstream's stock price to $8.65 as of April 20, 2022, the date of the final sale of our investment, from $10.34 as of December 31, 2021, partly offset by equity earnings on our equity method investments and a gain on our investment in the Investment Fund (defined and discussed in Note 1 to the Consolidated Financial Statements).

For 2021, we recognized income from investments due to a gain on our investment in Equitrans Midstream, equity earnings on our equity method investments and a gain on our investment in the Investment Fund.

For 2020, we recognized a loss from investments due to a loss on our investment in Equitrans Midstream.

(Income) loss from investments.

The change in (income) loss from investments was due primarily to a loss on our sale of our investment in Equitrans Midstream in 2022, partly offset by lower equity earnings recognized on our investment in LMM (defined in Note 1 to the Consolidated Financial Statements).

Dividend and other income.

Dividend and other income decreased for 2022 compared to 2021 due primarily to lower dividends received on our investment in Equitrans Midstream, which was fully disposed in April 2022, partly offset by higher dividends received on our investment in the Investment Fund.

Dividend and other income decreased for 2021 compared to 2020 due primarily to lower dividends received from our investment in Equitrans Midstream driven by a decrease in the number of shares of Equitrans Midstream's common stock that we owned as well as a decrease in the dividend amount per share.

Dividend and other income decreased for 2023 compared to 2022 due primarily to lower dividends received on our investment in the Investment Fund (defined in Note 1 to the Consolidated Financial Statements) as well as dividends received on our investment in Equitrans Midstream in 2022.

Loss on debt extinguishment.

During 2022, 2021 and 2020, we recognized a loss on debt extinguishment due to the debt repayments and repurchases discussed in Note 10 to the Consolidated Financial Statements.

Interest expense.

Interest expense decreased for 2022 compared to 2021 due primarily to reduced interest expense on our senior notes driven by lower balances and lower interest rates, reduced interest expense due to a reduction of letters of credit balances and higher interest income.

Interest expense increased for 2021 compared to 2020 due to increased interest incurred on new debt related to the Chevron Acquisition and Alta Acquisition and higher periodic borrowings under our credit facility.

See Note 10 to the Consolidated Financial Statements.

During 2022, we recognized a loss on debt extinguishment of $140.0 million due to our repayment and repurchase of debt, including our 3.00% notes due October 1, 2022.

Interest expense, net.

Interest expense decreased for 2023 compared to 2022 due primarily to higher interest income earned on cash on hand and lower interest expense on lower revolving credit facility borrowings, partly offset by higher interest expense on debt as a result of the August 2023 draw down of the Term Loan Facility (defined and discussed in Note 8 to the Consolidated Financial Statements) and October 2022 senior notes issuances.

The higher interest expense on debt was partly offset by our repayment and repurchase of debt disclosed in Note 8 to the Consolidated Financial Statements.

Income tax expense (benefit).

See Note 7 to the Consolidated Financial Statements.

See "Critical Accounting Policies and Estimates" included in this section and Note 1 to the Consolidated Financial Statements for a discussion of our accounting policies and significant assumptions related to accounting for natural gas, NGLs and oil producing activities and impairment of our oil and gas properties.

See "Critical Accounting Estimates" and Note 1 to the Consolidated Financial Statements for a discussion of our significant accounting policies and assumptions related to accounting for natural gas, NGLs and oil producing activities and impairment of our oil and gas properties.

See also Item 1A., "Risk Factors – Natural gas, NGLs and oil price declines, and changes in our development strategy, have resulted in impairment of certain of our assets.

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Capital Resources and Liquidity

Although we cannot provide any assurance, we believe cash flows from operating activities and availability under our credit facility should be sufficient to meet our cash requirements inclusive of, but not limited to, normal operating needs, debt service obligations, planned capital expenditures and commitments for at least the next twelve months and, based on current expectations, for the long term.

Credit Facility

We primarily use borrowings under our credit facility to fund working capital needs, timing differences between capital expenditures and other cash uses and cash flows from operating activities, margin deposit requirements on our derivative instruments and credit assurance requirements, including collateral, in support of our midstream service contracts, joint venture arrangements or construction contracts.

See Note 10 to the Consolidated Financial Statements for further discussion of our credit facility.

Although we cannot provide any assurance, we believe cash flows from operating activities and availability under our revolving credit facility should be sufficient to meet our cash requirements inclusive of, but not limited to, normal operating needs, debt service obligations, planned capital expenditures and commitments for at least the next twelve months and, based on current expectations, for the long term.

Revolving Credit Facility

We primarily use borrowings under our revolving credit facility to fund working capital needs, timing differences between capital expenditures and other cash uses and cash flows from operating activities, margin deposit requirements on our derivative instruments and credit assurance requirements, including collateral, in support of our midstream service contracts, joint venture arrangements or construction contracts.

See Note 8 to the Consolidated Financial Statements for further discussion of our revolving credit facility.

Known Contractual and Other Obligations;

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We have commitments for demand charges under existing long-term contracts and binding precedent agreements with various pipelines, some of which extend up to 20 years or longer.

We have entered into agreements to release some of our capacity under these long-term contracts.

We have entered into agreements to release some of our capacity under these long-term contracts, subject to certain conditions that are currently unsatisfied.

We also have commitments for processing capacity in order to extract heavier liquid hydrocarbons from the natural gas stream.

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federal income tax liability with the IRS through 2017 in January of 2023.

Other than the immaterial payment expected to be made in connection with the IRS settlement, we are currently unable to make reasonably reliable estimates of the period of cash settlement of these potential liabilities with taxing authorities.

We are currently unable to make reasonably reliable estimates of the period of cash settlement of these potential liabilities with taxing authorities.

Planned Capital Expenditures and Sales Volume .

In 2023, we expect to spend approximately $1.7 to $1.9 billion in total capital expenditures, excluding amounts attributable to noncontrolling interests and acquisitions.

We expect to fund planned capital expenditures with cash generated from operations and, if required, borrowings under our credit facility.

Because we are the operator of a high percentage of our acreage, the amount and timing of these capital expenditures are largely discretionary.

We could choose to defer a portion of these planned 2023 capital expenditures depending on a variety of factors, including prevailing and anticipated prices for natural gas, NGLs and oil;

In 2024, we expect to spend approximately $2.15 billion to $2.35 billion in total capital expenditures.

We expect to fund our capital expenditures with cash generated from operations and, if required, borrowings under our revolving credit facility.

Because we are the operator of a high percentage of our developed acreage, the amount and timing of certain of our capital expenditures is largely discretionary.

We could choose to defer a portion of our planned 2024 capital expenditures depending on a variety of factors, including prevailing and anticipated prices for natural gas, NGLs and oil;

the availability of necessary equipment, infrastructure and capital;

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and drilling, completion and acquisition costs.

In 2023, we expect our sales volume to be 1,900 to 2,000 Bcfe, excluding amounts attributable acquisitions.

Tug Hill and XcL Midstream Acquisition.

On September 6, 2022, EQT Corporation and EQT Production Company (the Buyer) entered into the Tug Hill and XcL Midstream Purchase Agreement, pursuant to which we agreed to acquire THQ Appalachia I, LLC's upstream assets and THQ-XcL Holdings I, LLC's gathering and processing assets through the acquisition of all of the issued and outstanding membership interests of each of THQ Appalachia I Midco, LLC and THQ-XcL Holdings I Midco, LLC for consideration of approximately $2.6 billion in cash and 55.0 million shares of EQT Corporation common stock, as adjusted pursuant to customary closing purchase price adjustments.

Upon execution of the Tug Hill and XcL Midstream Purchase Agreement, we deposited $150 million (together with any interest accrued thereon, the Escrowed Amount) into escrow, which was to be applied towards the cash consideration to be paid by the Buyer at the closing of the Tug Hill and XcL Midstream Acquisition (or, had the Tug Hill and XcL Midstream Purchase Agreement been terminated in accordance with its terms and conditions, the Escrowed Amount would have been disbursed to the Buyer or the sellers thereunder as provided in the Tug Hill and XcL Purchase Agreement).

On December 23, 2022, the Tug Hill and XcL Midstream Purchase Agreement was amended to, among other things, provide that the Escrowed Amount be released to the sellers thereunder, to be used exclusively to pay down certain of the Upstream Seller’s existing indebtedness, and the Upstream Seller issued to the Buyer an unsecured promissory note in an amount equal to the Escrowed Amount (the Upstream Seller Note).

Upon consummation of the Tug Hill and XcL Midstream Acquisition, the loans outstanding under the Upstream Seller Note will be applied towards the cash consideration to be paid by the Buyer at the closing of the Tug Hill and XcL Midstream Acquisition and such loans will be extinguished.

See Note 6 to the Consolidated Financial Statements for additional details regarding the Upstream Seller Note.

On October 4, 2022, we issued $500 million aggregate principal amount of 5.678% senior notes due October 1, 2025 and $500 million aggregate principal amount of 5.700% senior notes due April 1, 2028.

We intend to use the net proceeds from the sale of such notes, together with borrowings under the Term Loan Facility, cash on hand and/or borrowings under our credit facility, to fund the cash consideration for the Tug Hill and XcL Midstream Acquisition.

The Tug Hill and XcL Midstream Acquisition closing is subject to regulatory approvals.

In 2024, we expect our sales volume to be 2,200 Bcfe to 2,300 Bcfe.

Operating Activities

Net cash provided by operating activities was $3,466 million, $1,662 million and $1,538 million for 2022, 2021 and 2020, respectively.

The increase in 2022 compared to 2021 was due primarily to higher cash operating revenues, favorable changes in working capital and increased distribution of earnings from equity method investments, partly offset by higher net cash settlements paid on derivatives and higher cash operating expenses.

The favorable changes in working capital also included cash received from the Cash Payment Option pursuant to the Consolidated GGA (each defined and discussed in Note 5 to the Consolidated Financial Statements).

The increase in 2021 compared to 2020 was due primarily to higher cash operating revenues, partly offset by the cash settlements paid on derivatives, higher cash operating expenses and income tax refunds received in the prior year.

Net cash provided by operating activities was $3,179 million and $3,466 million for 2023 and 2022, respectively.

The decrease in 2023 compared to 2022 was due primarily to lower cash operating revenues, partly offset by net cash settlements received on derivatives in 2023 compared to net cash settlements paid on derivatives in 2022, favorable changes in working capital driven by declining accounts receivable and lower margin postings.

Our cash flows from operating activities are affected by movements in the market price for commodities.

We are unable to predict such movements outside of the current market view as reflected in forward strip pricing.

Refer to Item 1A., "Risk Factors – Natural gas, NGLs and oil price volatility, or a prolonged period of low natural gas, NGLs and oil prices, may have an adverse effect on our revenue, profitability, future rate of growth, liquidity and financial position." for further information.

For a discussion of potential commodity market risks, refer to Item 1A., "Risk Factors – Natural gas, NGLs and oil price volatility, or a prolonged period of low natural gas, NGLs and oil prices, may have an adverse effect on our revenue, profitability, future rate of growth, liquidity and financial position."

Investing Activities

Net cash used in investing activities was $1,422 million, $2,073 million and $1,556 million for 2022, 2021 and 2020, respectively.

The decrease in 2022 compared to 2021 was due to cash paid for acquisitions in 2021 and proceeds from the sale of our remaining investment in Equitrans Midstream common stock in 2022, partly offset by increased capital expenditures and a cash deposit paid pursuant to the Tug Hill and XcL Midstream Purchase Agreement, which has since been transitioned into a loan to the Upstream Seller (see Note 6 to the Consolidated Financial Statements for additional details).

The increase in 2021 compared to 2020 was due primarily to higher cash paid for acquisitions and proceeds from the sale of assets in 2020.

Net cash used in investing activities was $4,314 million and $1,422 million for 2023 and 2022, respectively.

The increase in 2023 compared to 2022 was attributable primarily to cash paid for the Tug Hill and XcL Midstream Acquisition in 2023 and increased capital expenditures.

The following table summarizes our capital expenditures.

Years Ended December 31,

2022 2021 2020

Reserve development $ 1,131 $ 828 $ 839

Land and lease (a) 138 144 121

Reserve development (a) $ 1,587 $ 1,131

Land and lease (b) 130 138

Other production infrastructure 63 82

Midstream 31 6

Capitalized overhead 60 51

Capitalized interest 41 28

Other production infrastructure 82 47 40

Other corporate items 10 9 11

Total capital expenditures 1,925 1,440

Non-cash items (b) (40) (49) (37)

Add (deduct):

Non-cash items (c) 94 (40)

Total cash capital expenditures $ 2,019 $ 1,400

(a) Capital expenditures attributable to noncontrolling interest were $12.8 million, $9.6 million and $4.9 million for the years ended December 31, 2022, 2021 and 2020, respectively.

(b) Represents the net impact of non-cash capital expenditures, including the effect of timing of receivables from working interest partners, accrued capital expenditures and capitalized share-based compensation costs.

(a) Includes capital expenditures for water infrastructure of $35.9 million and $44.5 million for 2023 and 2022, respectively.

(b) Capital expenditures attributable to noncontrolling interests were $8.5 million and $12.8 million for 2023 and 2022, respectively.

(c) Represents the net impact of non-cash capital expenditures, including the effect of timing of receivables from working interest partners, accrued capital expenditures and capitalized share-based compensation costs.

The impact of accrued capital expenditures includes the current period estimate, net of the reversal of the prior period accrual.

Financing Activities

Net cash (used in) provided by financing activities was $(699) million, $506 million and $32 million for 2022, 2021 and 2020, respectively.

For 2022, the primary uses of financing cash flows were repayment and retirement of debt, repurchase and retirement of EQT Corporation common stock and payment of dividends and the primary source of financing cash flows was net proceeds from the issuance of debt.

For 2021, the primary source of financing cash flows was proceeds from the issuance of debt, and the primary uses of financing cash flows were net credit facility borrowings and repayment and retirement of debt.

For 2020, the primary source of financing cash flows was proceeds from the issuance of debt and equity, and the primary use of financing cash flows was repayment and retirement of debt.

See Note 10 to the Consolidated Financial Statements for further discussion of our debt.

On February 9, 2023, our Board of Directors declared a quarterly cash dividend of $0.15 per share, payable on March 1, 2023, to shareholders of record at the close of business on February 21, 2023.

Depending on our actual and anticipated sources and uses of liquidity, prevailing market conditions and other factors, we may from time to time seek to retire or repurchase our outstanding debt or equity securities through cash purchases in the open market or privately negotiated transactions.

Net cash used in financing activities was $243 million and $699 million for 2023 and 2022, respectively.

For 2023, the primary uses of financing cash flows were repayment and retirement of debt, payment of dividends and repurchase and retirement of EQT Corporation common stock, and the primary source of financing cash flows was proceeds from the Term Loan Facility borrowings.

For 2022, the primary uses of financing cash flows were repayment and retirement of debt, repurchase and retirement of EQT Corporation common stock and payment of dividends, and the primary source of financing cash flows was proceeds from the issuance of debt.

See Note 8 to the Consolidated Financial Statements for further discussion of our debt and borrowings under our revolving credit facility and the Term Loan Facility, including discussion of events that occurred subsequent to December 31, 2023.

On February 8, 2024, our Board of Directors declared a quarterly cash dividend of $0.1575 per share of EQT Corporation common stock, payable on March 1, 2024, to shareholders of record at the close of business on February 20, 2024.

Depending on our actual and anticipated sources and uses of liquidity, prevailing market conditions and other factors, we may from time to time seek to redeem or repurchase our outstanding debt or equity securities through tender offers or other cash purchases in the open market or privately negotiated transactions.

The amounts involved in any such transactions may be material.

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Security Ratings and Financing Triggers

The table below reflects the credit ratings and rating outlooks assigned to our debt instruments at February 10, 2023.

The table below reflects the credit ratings and rating outlooks assigned to our debt instruments as of December 31, 2023 .

Our credit ratings and rating outlooks are subject to revision or withdrawal at any time by the assigning rating agency, and each rating should be evaluated independent from any other rating.

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Rating agency Senior notes Outlook

Moody's Investors Service (Moody's) Ba1 Positive

Standard & Poor's Ratings Service (S&P) BBB- Stable

Fitch Ratings Service (Fitch) BBB- Stable

Changes in credit ratings may affect our access to the capital markets, the cost of short-term debt through interest rates and fees under our lines of credit, the interest rate on our Term Loan Facility and senior notes with adjustable rates, the rates available on new long-term debt, our pool of investors and funding sources, the borrowing costs and margin deposit requirements on our OTC derivative instruments and credit assurance requirements, including collateral, in support of our midstream service contracts, joint venture arrangements or construction contracts.

Moody's Investors Service (Moody's) Baa3 Stable

Standard & Poor's Ratings Service (S&P) BBB–

Fitch Ratings Service (Fitch) BBB–

Changes in credit ratings may affect our access to the capital markets, the cost of short-term debt through interest rates and fees under our revolving credit facility, the interest rate on the Term Loan Facility and senior notes with adjustable rates, the rates available on new long-term debt, our pool of investors and funding sources, the borrowing costs and margin deposit requirements on our OTC derivative instruments and credit assurance requirements, including collateral, in support of our midstream service contracts, joint venture arrangements or construction contracts.

Margin deposits on our OTC derivative instruments are also subject to factors other than credit rating, such as natural gas prices and credit thresholds set forth in the agreements between us and our hedging counterparties.

As of February 10, 2023, we had sufficient unused borrowing capacity, net of letters of credit, under our credit facility to satisfy any requests for margin deposit or other collateral that our counterparties are permitted to request of us pursuant to our OTC derivative instruments, midstream services contracts and other contracts.

As of February 10, 2023, such assurances could be up to approximately $0.6 billion, inclusive of letters of credit, OTC derivative instrument margin deposits and other collateral posted of approximately $0.2 billion in the aggregate.

See Notes 3 and 10 to the Consolidated Financial Statements for further information.

Our debt agreements and other financial obligations contain various provisions that, if not complied with, could result in default or event of default under our credit facility and Term Loan Facility, mandatory partial or full repayment of amounts outstanding, reduced loan capacity or other similar actions.

The most significant covenants and events of default under the debt agreements relate to maintenance of a debt-to-total capitalization ratio, limitations on transactions with affiliates, insolvency events, nonpayment of scheduled principal or interest payments, acceleration of other financial obligations and change of control provisions.

Our credit facility and Term Loan Facility contains financial covenants that require us to have a total debt-to-total capitalization ratio no greater than 65%.

Our debt agreements and other financial obligations contain various provisions that, if not complied with, could result in default or event of default under our revolving credit facility and the Term Loan Facility, mandatory partial or full repayment of amounts outstanding, reduced loan capacity or other similar actions.

The most significant covenants and events of default under our debt agreements relate to maintenance of a debt-to-total capitalization ratio, limitations on transactions with affiliates, insolvency events, nonpayment of scheduled principal or interest payments, acceleration of other financial obligations and change of control provisions.

Our revolving credit facility and the Term Loan Facility contain financial covenants that require us to have a total debt-to-total capitalization ratio no greater than 65%.

As of December 31, 2023, we were in compliance with all debt provisions and covenants under our debt agreements.

See Note 10 to the Consolidated Financial Statements for a discussion of borrowings under our credit facility.

As of December 31, 2022, we had not yet borrowed, and thus, had no borrowings, under the Term Loan Facility.

See Note 8 to the Consolidated Financial Statements for a discussion of borrowings under our revolving credit facility and the Term Loan Facility.

Commodity Risk Management

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Hedged Volume (MMDth/d) 3.1 2.9 2.6 1.4

Volume (MMDth) 45 41 42 14 —

Price ($/Dth) $ 6.19 $ 4.77 $ 4.77 $ 4.77 $ —

Swaps – Short

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Strike ($/Dth) $ 4.20 $ 4.05 $ 4.05 $ 4.10

Fixed Price Sales

Volume (MMDth) 1 1 1 — —

Price ($/Dth) $ 2.43 $ 2.38 $ 2.38 $ — $ —

Option Premiums

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Our recently issued accounting standards are described in Note 1 to the Consolidated Financial Statements.

Critical Accounting Policies and Estimates

Critical Accounting Estimates

Our significant accounting policies are described in Note 1 to the Consolidated Financial Statements.

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The preparation of the Consolidated Financial Statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosure of contingent assets and liabilities.

The following critical accounting policies, which were reviewed by the Audit Committee of our Board of Directors (the Audit Committee), relate to our more significant judgments and estimates used in the preparation of our Consolidated Financial Statements.

The following critical accounting estimates, which were reviewed by the Audit Committee of our Board of Directors (the Audit Committee), relate to our more significant judgments and estimates used in the preparation of our Consolidated Financial Statements.

Actual results could differ from our estimates.

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A material change in the estimated volume of reserves could have an impact on the depletion rate calculation and our Consolidated Financial Statements.

We estimate future net cash flows from natural gas, NGLs and crude oil reserves based on selling prices and costs using a twelve-month average price, which is calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the twelve-month period and, as such, is subject to change in subsequent periods.

We estimate future net cash flows from natural gas, NGLs and oil reserves based on selling prices and costs using a twelve-month average price, which is calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the twelve-month period and, as such, is subject to change in subsequent periods.

Operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation.

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Future results of operations and the strength of our Consolidated Balance Sheet for any quarterly or annual period could be materially affected by changes in our assumptions.

Based on proved reserves at December 31, 2022, we estimate that a 1% change in proved reserves would decrease or increase 2023 depletion expense by approximately $16 million and $20 million, respectively, based on current production estimates for 2023.

Based on proved reserves as of December 31, 2023, we estimate that a 1% change in proved reserves would decrease or increase 2024 depletion expense by approximately $15 million and $27 million, respectively, based on current production estimates for 2024.

See also Item 1A., "Risk Factors – Natural gas, NGLs and oil price volatility, or a prolonged period of low natural gas, NGLs and oil prices, may have an adverse effect on our revenue, profitability, future rate of growth, liquidity and financial position."

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We recognize deferred tax assets and liabilities for the expected future tax consequences of events that have been included in our Consolidated Financial Statements or tax returns.

See Note 1 to the Consolidated Financial Statements for a discussion of accounting policies related to income taxes and Note 9 to the Consolidated Financial Statements for a discussion of deferred tax assets, valuation allowances and the amount of financial statement benefit recorded for uncertain tax positions.

See Note 1 to the Consolidated Financial Statements for a discussion of significant accounting policies related to income taxes and Note 7 to the Consolidated Financial Statements for a discussion of deferred tax assets, valuation allowances and the amount of financial statement benefit recorded for uncertain tax positions.

We believe income taxes are "critical accounting estimates" because we must assess the likelihood that our deferred tax assets will be recovered from future taxable income and exercise judgment on the amount of financial statement benefit recorded for uncertain tax positions.

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Accounting for a business combination requires a company to record the identifiable assets and liabilities acquired at fair value.

In the third quarter of 2021, we completed the Alta Acquisition, and in the fourth quarter of 2020, we completed the Chevron Acquisition.

See Note 6 to the Consolidated Financial Statements for a discussion of the most significant assumptions used to estimate the fair value of the assets and liabilities acquired.

We believe business combinations are "critical accounting estimates" because the valuation of acquired assets and liabilities involves significant judgment about future events.

In the third quarter of 2023, we completed the Tug Hill and XcL Midstream Acquisition, and in the third quarter of 2021, we completed the Alta Acquisition (defined and discussed in Note 6 to the Consolidated Financial Statements).

See Note 6 to the Consolidated Financial Statements for a discussion of the most significant assumptions used to estimate the fair value of the assets acquired and liabilities assumed.

We believe business combinations are "critical accounting estimates" because the valuation of acquired assets and assumed liabilities involves significant judgment about future events.

Future results of operations for any quarterly or annual period could be materially affected by changes in our assumptions.

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 7. Management’s Discussion and Analysis