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Item 7. Management’s Discussion and Analysis

2023-02-16 compared with 2022-02-10 · 186 added, 96 removed, 282 unchanged (50% 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 not designated as hedges, 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 the first quarter of 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 2021 include the results of approximately six months of our operation of assets acquired in the Alta Acquisition, which closed in July 2021, the results of a full year of our operation of assets acquired from Chevron U.S.A.

(the Chevron Acquisition), which closed in November 2020, and nine months of our operation of assets acquired from Reliance Marcellus, LLC (the Reliance Asset Acquisition).

See Note 6 to the Consolidated Financial Statements for further discussion of the Alta Acquisition, Chevron Acquisition and Reliance Asset Acquisition.

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, 2020, which is incorporated herein by reference, for discussion and analysis of consolidated results of operations for the year ended December 31, 2019.

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.

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.

See "Investing Activities" under "Capital Resources and Liquidity" for a discussion of capital expenditures.

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.

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.

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.

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.

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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Basis ($/Mcf) (a) $ (0.77) $ (0.63) $ (0.47)

Cash settled basis swaps not designated as hedges ($/Mcf) (0.07) 0.05

Cash settled basis swaps ($/Mcf) (0.02) (0.07) 0.05

Average differential, including cash settled basis swaps ($/Mcf) $ (0.79) $ (0.70) $ (0.42)

Average adjusted price ($/Mcf) $ 6.20 $ 3.47 $ 1.78

Cash settled derivatives not designated as hedges ($/Mcf) (1.09) 0.59

Cash settled derivatives ($/Mcf) (3.20) (1.09) 0.59

Average natural gas price, including cash settled derivatives ($/Mcf) $ 3.00 $ 2.38 $ 2.37

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Sales volume (Mbbl) 9,456 10,700 7,451

Price ($/Bbl) $ 44.50 $ 20.51

Cash settled derivatives not designated as hedges ($/Bbl) (12.32) (0.12)

Average price, including cash settled derivatives ($/Bbl) $ 32.18 $ 20.39

NGLs sales $ 344,260 $ 151,877

NGLs price ($/Bbl) $ 53.26 $ 44.50 $ 20.51

Cash settled derivatives ($/Bbl) (3.91) (12.32) (0.12)

Average NGLs price, including cash settled derivatives ($/Bbl) $ 49.35 $ 32.18 $ 20.39

NGLs sales, including cash settled derivatives $ 466,664 $ 344,260 $ 151,877

Sales volume (MMcfe) (b) 35,100 37,548 29,489

Sales volume (Mbbl) 5,850 6,258 4,914

Price ($/Bbl) $ 8.85 $ 3.48

Ethane price ($/Bbl) $ 14.20 $ 8.85 $ 3.48

Ethane sales $ 83,096 $ 55,393 $ 17,085

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Sales volume (Mbbl) 1,027 1,625 804

Price ($/Bbl) $ 56.82 $ 25.57

Oil price ($/Bbl) $ 77.06 $ 56.82 $ 25.57

Oil sales $ 79,160 $ 92,334 $ 20,574

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Years Ended December 31,

2022 2021 2020

(Thousands, unless otherwise noted)

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Add (deduct):

Loss (gain) on derivatives not designated as hedges 3,775,042 (400,214)

Net cash settlements (paid) received on derivatives not designated as hedges (2,091,003) 897,190

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

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Operating revenues:

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

(Loss) gain on derivatives not designated as hedges (3,775,042) 400,214 (4,175,256) (1,043.3)

Sales of natural gas, NGLs and oil $ 12,114,168 $ 6,804,020 $ 5,310,148 78.0

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

Net marketing services and other 26,453 35,685 (9,232) (25.9)

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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.

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, 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 and from wells turned in-line during 2021, partly offset by sales volume decreases 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 2020 production.

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.

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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 not designated as hedges, which are included in average realized price but may not be included in operating revenues.

(Loss) gain on derivatives not designated as hedges.

For 2021 and 2020, we recognized a loss of $3,775.0 million and a gain of $400.2 million, respectively, on derivatives not designated as hedges.

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.

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Operating Expenses

The following table presents information on our production-related operating expenses.

Years Ended December 31,

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Production depletion 0.85 0.89 (0.04) (4.5)

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.

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.

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.

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.

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.

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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.

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.

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(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 (defined and discussed in Note 8 to the Consolidated Financial Statements) from the 2020 Divestiture.

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.

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See Note 5 to the Consolidated Financial Statements.

(Income) loss from investments.

For 2021, we recognized income on our investments in Equitrans Midstream and Laurel Mountain Midstream (see Note 6 to the Consolidated Financial Statements).

Our investment in Equitrans Midstream fluctuates with changes in Equitrans Midstream's stock price, which was $10.34 and $8.04 as of December 31, 2021 and 2020, respectively.

For 2020, we recognized a loss on our investment in Equitrans Midstream due to a decrease in Equitrans Midstream's stock price.

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.

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.

Loss on debt extinguishment.

During 2021, we recognized a loss on debt extinguishment of $9.8 million due to fees incurred for a bridge-loan commitment related to the Alta Acquisition and the repayment of our 4.875% senior notes.

During 2020, we recognized a loss on debt extinguishment of $25.4 million related to the repayment of all or a portion of our 4.875% senior notes, 2.50% senior notes, 3.00% senior notes, floating rate notes and term loan facility.

See Note 10 to the Consolidated Financial Statements.

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

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.

Income tax benefit.

Income tax expense (benefit).

See Note 9 to the Consolidated Financial Statements.

Impairment of Oil and Gas Properties

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

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

Aggregate future payments for these items as of December 31, 2021 were $23.8 billion, composed of $1.7 billion in 2022, $1.8 billion in 2023, $1.8 billion in 2024, $1.8 billion in 2025, $1.7 billion in 2026 and $15.0 billion thereafter (primarily in 2027 through 2042).

In addition, we have commitments to pay for services and materials related to our operations, which primarily include minimum volume commitments to obtain water services and electric hydraulic fracturing services and commitments to purchase equipment, materials and sand.

As of December 31, 2021, future commitments under these contracts were $135.6 million in 2022, $99.0 million in 2023, $47.5 million in 2024, $40.0 million in 2025, $40.0 million in 2026 and $178.3 million thereafter.

See Note 13 to the Consolidated Financial Statements for further discussion, including details regarding aggregate future payments for these items.

Contractual Commitments.

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Unrecognized Tax Benefits.

As discussed further in Note 9 to the Consolidated Financial Statements, as of December 31, 2021, we had a total reserve for unrecognized tax benefits of $94.1 million and an additional reserve of $97.2 million that was offset against deferred tax assets for general business tax credit carryforwards and NOLs.

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

As discussed further in Note 9 to the Consolidated Financial Statements, as of December 31, 2022, we had a total reserve for unrecognized tax benefits of $105.4 million and an additional reserve of $110.7 million that was offset against deferred tax assets for general business tax credit carryforwards and net operating losses (NOLs).

We settled our consolidated U.S.

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.

Planned Capital Expenditures and Sales Volume .

In 2022, we expect to spend approximately $1.30 to $1.45 billion in total capital expenditures, excluding amounts attributable to noncontrolling interest.

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.

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and drilling, completion and acquisition costs.

Sales volume in 2022 is expected to be 1,950 to 2,050 Bcfe.

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.

Operating Activities

Net cash provided by operating activities was $1,662 million for 2021 compared to $1,538 million for 2020.

The increase was due primarily to higher cash operating revenues, partly offset by the cash settlements paid on derivatives not designated as hedges, higher cash operating expenses and income tax refunds received in the prior year.

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.

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

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Investing Activities

Net cash used in investing activities was $2,073 million for 2021 compared to $1,556 million for 2020.

The increase 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 $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.

The following table summarizes our capital expenditures.

Years Ended December 31,

2022 2021 2020

Reserve development $ 1,131 $ 828 $ 839

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Total cash capital expenditures $ 1,400 $ 1,055 $ 1,042

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

(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.

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Financing Activities

Net cash provided by financing activities was $506 million for 2021 compared to $32 million for 2020.

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.

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The amounts involved in any such transactions may be material.

Additionally, we plan to dispose of our remaining retained shares of Equitrans Midstream's common stock and use the proceeds to reduce our debt.

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, 2020, which is incorporated herein by reference, for discussion and analysis of operating, investing and financing activities for the year ended December 31, 2019.

See Note 10 to the Consolidated Financial Statements for discussion of redemptions and repurchases of debt and Note 11 to the Consolidated Financial Statements for discussion of repurchases of EQT Corporation common stock.

Security Ratings and Financing Triggers

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Rating agency Senior notes Outlook

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

Standard & Poor's Ratings Service (S&P) BB+ Positive

Fitch Ratings Service (Fitch) BB+ 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 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) 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.

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.

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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.

During the third quarter of 2021, we amended agreements with six of our largest OTC hedge counterparties to permanently or temporarily reduce or eliminate our margin posting obligations associated with our OTC derivative instruments with such OTC hedge counterparties.

The purpose of such amendments was to mitigate the amount of cash collateral that we would otherwise have been required to post based on current NYMEX strip pricing.

As of February 4, 2022, our margin balance on our existing hedge portfolio, including both OTC and broker margin balances, was approximately $0.3 billion, compared to approximately $0.1 billion as of December 31, 2020, despite a significant increase in natural gas prices.

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, mandatory partial or full repayment of amounts outstanding, reduced loan capacity or other similar actions.

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 contains financial covenants that require us to have a total debt-to-total capitalization ratio no greater than 65%.

The calculation of this ratio excludes the effects of accumulated other comprehensive loss.

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%.

As of December 31, 2022, 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.

Commodity Risk Management

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The derivative commodity instruments that we use are primarily swap, collar and option agreements.

The following table summarizes the approximate volume and prices of our NYMEX hedge positions through 2024 as of February 4, 2022.

The following table summarizes the approximate volume and prices of our NYMEX hedge positions as of February 10, 2023.

The difference between the fixed price and NYMEX price is included in average differential presented in our price reconciliation in "Average Realized Price Reconciliation." The fixed price natural gas sales agreements can be physically or financially settled.

Q1 2023(a) Q2 2023 Q3 2023 Q4 2023 2024

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Hedged Volume (MMDth/d) 3.3 3.4 3.4 3.2 0.6

Swaps (includes Futures)

Volume (MMDth) 45 41 42 14 —

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

Calls - Net Short

Swaps – Short

Volume (MMDth) 45 41 42 42 2

Short Strike ($/Dth) $ 3.26 $ 3.00 $ 3.00 $ 3.00 $ 4.38 $ 3.11

Puts - Net Long

Price ($/Dth) $ 2.97 $ 2.53 $ 2.53 $ 2.53 $ 2.67

Volume (MMDth) 46 40 40 40 51

Long Strike ($/Dth) $ 2.68 $ 2.68 $ 2.68 $ 2.68 $ 2.90 $ 2.45

Fixed Price Sales (b)

Strike ($/Dth) $ 3.43 $ 2.72 $ 2.72 $ 2.72 $ 3.20

Calls – Short

Volume (MMDth) 238 300 303 197 255

Strike ($/Dth) $ 9.42 $ 4.85 $ 4.85 $ 4.69 $ 5.07

Volume (MMDth) 299 304 308 268 204

Strike ($/Dth) $ 4.50 $ 3.39 $ 3.39 $ 3.51 $ 4.21

Fixed Price Sales

Volume (MMDth) 1 1 1 — —

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

Option Premiums

Cash Settlement of Deferred Premiums (millions) $ (98) $ (70) $ (71) $ (92) $ (10)

(a) January 1 through March 31.

(b) The difference between the fixed price and NYMEX price is included in average differential presented in our price reconciliation in "Average Realized Price Reconciliation." The fixed price natural gas sales agreements can be physically or financially settled.

For 2022, 2023 and 2024, we have natural gas sales agreements for approximately 18 MMDth, 88 MMDth and 11 MMDth, respectively, that include average NYMEX ceiling prices of $3.17, $2.84 and $3.21, respectively.

During the third and fourth quarters of 2021, we purchased $67 million of net winter calls to reposition our 2021 and 2022 hedge portfolio to enable incremental upside participation in rising natural gas prices and to further mitigate potential incremental margin posting requirements.

As of December 31, 2021, the remaining positions cover approximately 45 net MMDth in the first quarter of 2022 and have been excluded from the table above.

We have also entered into derivative instruments to hedge basis.

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Off-Balance Sheet Arrangements

See Note 17 to the Consolidated Financial Statements for a discussion of our guarantees.

As of December 31, 2022, we did not have any material off-balance sheet arrangements other than the commitments described in Note 13 to the Consolidated Financial Statements.

Commitments and Contingencies

In the ordinary course of business, various legal and regulatory claims and proceedings are pending or threatened against us.

While the amounts claimed may be substantial, we are unable to predict with certainty the ultimate outcome of such claims and proceedings.

We accrue legal and other direct costs related to loss contingencies when actually incurred.

We have established reserves that we believe to be appropriate for pending matters and, after consultation with counsel and giving appropriate consideration to available insurance, we believe that the ultimate outcome of any matter currently pending against us will not materially affect our financial condition, results of operations or liquidity.

See Note 13 to the Consolidated Financial Statements for a discussion of our commitments and contingencies.

See Item 3., "Legal Proceedings."

Recently Issued Accounting Standards

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See Note 1 to the Consolidated Financial Statements for a discussion of the fair value measurement and any subsequent impairments of our proved and unproved oil and gas properties and other long-lived assets as well as evaluation of the recoverability of capitalized costs of unproved oil and gas properties.

We believe accounting for gas, NGLs and oil producing activities is a "critical accounting estimate" because the evaluations of impairment of proved properties involve significant judgment about future events, such as future sales prices of natural gas and NGLs and future production costs, as well as the amount of natural gas and NGLs recorded and timing of recoveries.

We believe accounting for natural gas, NGLs and oil producing activities is a "critical accounting estimate" because the evaluations of impairment of proved properties involve significant judgment about future events, such as future sales prices of natural gas and NGLs and future production costs, as well as the amount of natural gas and NGLs recorded and timing of recoveries.

Significant changes in these estimates could result in the costs of our proved and unproved properties not being recoverable;

therefore, we would be required to recognize impairment.

See "Impairment of Oil and Gas Properties" and Note 1 to the Consolidated Financial Statements for additional information on impairments of our proved and unproved oil and gas properties.

An estimate of the sensitivity to changes in our assumptions is not practicable given the numerous assumptions that can materially affect our estimates.

See Note 1 to the Consolidated Financial Statements for additional information on impairments of our proved and unproved 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.

Future declines in commodity prices, increases in operating costs or adverse changes in well performance or additional changes in our development strategy may result in additional write-downs of the carrying amounts of our assets, including long-lived intangible assets, which could materially and adversely affect our results of operations in future periods."

Oil and Gas Reserves.

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

Income tax expense is based on future statutory tax rates and tax deductions and credits available under current laws.

Income tax expense is based on currently enacted statutory tax rates and tax deductions and credits available under current laws.

We believe oil and gas reserves is a "critical accounting estimate" because we must periodically reevaluate proved reserves along with estimates of future production rates, production costs and the timing of development expenditures.

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.

Significant changes in these estimates could result in a change to our estimated reserves, which could lead to a material change to our production depletion expense.

See "Impairment of Oil and Gas Properties" for additional information on our oil and gas reserves.

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.

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."

Income Taxes.

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A change to future taxable income or tax planning strategies could impact our ability to utilize deferred tax assets, which would increase or decrease our income tax expense and taxes paid.

An estimate of the sensitivity to changes in our assumptions is not practicable given the numerous assumptions that can materially affect our estimates.

Derivative Instruments.

We enter into derivative commodity instrument contracts primarily to reduce exposure to commodity price risk associated with future sales of natural gas production.

We enter into derivative commodity instrument contracts primarily to reduce exposure to commodity price risk associated with future sales of our natural gas production.

See Note 4 to the Consolidated Financial Statements for a description of the fair value hierarchy.

See also Note 5 to the Consolidated Financial Statements for a discussion of the derivative liability recorded in connection with the Equitrans Share Exchange.

The values reported in the Consolidated Financial Statements change as these estimates are revised to reflect actual results or as market conditions or other factors, many of which are beyond our control, change.

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

An estimate of the sensitivity to changes in our assumptions is not practicable given the numerous assumptions that can materially affect our estimates.

Contingencies and Asset Retirement Obligations.

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If the expected amount and timing of our asset retirement obligations change, we will be required to adjust the carrying value of our liabilities in future periods.

Contract Asset.

In the first quarter of 2020, we entered into two share purchase agreements with Equitrans Midstream to sell to Equitrans Midstream 50% of our ownership of Equitrans Midstream's common stock in exchange for a combination of cash and rate relief under certain of our gathering agreements with EQM, an affiliate of Equitrans Midstream.

See Note 5 to the Consolidated Financial Statements for further discussion of the key assumptions used in the fair value calculation of the contract asset and Note 1 to the Consolidated Financial Statements for a discussion of impairment considerations.

We believe the Consolidated GGA contract asset is a "critical accounting estimate" because the assumptions used in the valuation of the contract asset involved significant judgment.

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

A change in the estimated production volume forecast, the market-based discount rate or the probability-weighted estimate of the in-service date of the Mountain Valley Pipeline could have resulted in a change in the valuation of the contract asset.

Convertible Notes.

In the second quarter of 2020, we issued the Convertible Notes and Capped Call Transactions (each defined and discussed in Note 10 to the Consolidated Financial Statements).

See Note 10 to the Consolidated Financial Statements for a discussion of our valuation of the liability and equity components and accounting for the Capped Call Transactions and Note 1 to the Consolidated Financial Statements for the effect of the Convertible Notes on our earnings per share calculations.

We believe the accounting complexity of the Convertible Notes is a "critical accounting estimate" because we used judgment to determine the balance sheet classification, to determine the treatment of the Capped Call Transactions and to determine the existence of any derivatives that may require separate accounting under applicable accounting guidance.

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

An estimate of the sensitivity to changes in our assumptions is not practicable given the numerous assumptions that can materially affect our estimates.

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