EQT Corp (EQT) FY 2022 MD&A

Item 7.        Management's Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of financial condition and results of operations should be read in conjunction with the Consolidated Financial Statements and the notes thereto included in Item 8., "Financial Statements and Supplementary Data."

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.

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

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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. Adjusted operating revenues should not be considered as an alternative to total operating revenues. See "Non-GAAP Financial Measures Reconciliation" for a reconciliation of adjusted operating revenues with total operating revenues, the most directly comparable financial measure calculated in accordance with GAAP.

(a)Basis represents the difference between the ultimate sales price for natural gas, including the effects of delivered price benefit or deficit associated with our firm transportation agreements, and the NYMEX natural gas price.

(b)NGLs, ethane and oil were converted to Mcfe at a rate of six Mcfe per barrel.

(c)Total natural gas and liquids sales, including cash settled derivatives, is also referred to in this report as adjusted operating revenues, a non-GAAP supplemental financial measure.

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Non-GAAP Financial Measures Reconciliation

The table below reconciles adjusted operating revenues, a non-GAAP supplemental financial measure, with total operating revenues, its most directly comparable financial measure calculated in accordance with GAAP. Adjusted operating revenues (also referred to in this report as total natural gas and liquids sales, including cash settled derivatives) is presented because it is an important measure we use to evaluate period-to-period comparisons of earnings trends. Adjusted operating revenues excludes the revenue impacts of changes in the fair value of derivative instruments prior to settlement and net marketing services and other. 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. 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. We believe that adjusted operating revenues provides useful information to investors for evaluating period-to-period comparisons of earnings trends.

Sales Volume and Revenues

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.

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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. 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.

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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, 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.

Operating Expenses

Gathering. 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.

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Processing. 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. 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. 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.

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Gathering. 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. 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. 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

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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 2021 compared to 2020 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.

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.

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. 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.

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 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.

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Income tax expense (benefit). See Note 9 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 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."

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.

Known Contractual and Other Obligations; Planned Capital Expenditures

Purchase Obligations. 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 also have commitments for processing capacity in order to extract heavier liquid hydrocarbons from the natural gas stream. 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. See Note 13 to the Consolidated Financial Statements for further discussion, including details regarding aggregate future payments for these items.

Contractual Commitments. We have contractual commitments under our debt agreements, including interest payments and principal repayments. See Note 10 to the Consolidated Financial Statements for further discussion of the contractual commitments under our debt agreements, including the timing of principal repayments.

Unrecognized Tax Benefits. 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 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; the availability of necessary equipment, infrastructure and capital; the receipt and timing of required regulatory permits and approvals; 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.

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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 $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. 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.

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.

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The following table summarizes our capital expenditures.

(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. 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. The amounts involved in any such transactions may be material. 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

The table below reflects the credit ratings and rating outlooks assigned to our debt instruments at February 10, 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. We cannot ensure that a rating will remain in effect for any given period of time or that a rating will not be lowered or withdrawn by a rating agency if, in the rating agency's judgment, circumstances so warrant. See Note 3 to the Consolidated Financial Statements for a description of what is deemed investment grade.

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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.

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%. 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.

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Commodity Risk Management

The substantial majority of our commodity risk management program is related to hedging sales of our produced natural gas. The overall objective of our hedging program is to protect cash flows from undue exposure to the risk of changing commodity prices. 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 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.

(a)January 1 through March 31.

We have also entered into derivative instruments to hedge basis. We may use other contractual agreements to implement our commodity hedging strategy from time to time.

See Item 7A., "Quantitative and Qualitative Disclosures About Market Risk" and Note 3 to the Consolidated Financial Statements for further discussion of our hedging program.

Off-Balance Sheet Arrangements

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

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

Recently Issued Accounting Standards

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

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Critical Accounting Policies and Estimates

Our significant accounting policies are described in Note 1 to the Consolidated Financial Statements. Management's discussion and analysis of the Consolidated Financial Statements and results of operations are based on our Consolidated Financial Statements, which have been prepared in accordance with GAAP. 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. Actual results could differ from our estimates.

Accounting for Gas, NGLs and Oil Producing Activities. We use the successful efforts method of accounting for our oil and gas producing activities. 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 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. 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. Proved oil and gas reserves, as defined by SEC Regulation S-X Rule 4-10, are those quantities of oil and gas that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs and under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire unless evidence indicates that renewal is reasonably certain regardless of whether deterministic or probabilistic methods are used for the estimation.

Our estimates of proved reserves are reassessed annually using geological, reservoir and production performance data. Reserve estimates are prepared by our engineers and audited by independent engineers. Revisions may result from changes in, among other things, reservoir performance, development plans, prices, operating costs, economic conditions and governmental restrictions. Decreases in prices, for example, may cause a reduction in certain proved reserves due to reaching economic limits sooner. 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. 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 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. 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."

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Income Taxes. 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.

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. To the extent that a valuation allowance or uncertain tax position is established or increased or decreased during a period, we record an expense or benefit in income tax expense in our Statements of Consolidated Operations. Future results of operations for any quarterly or annual period could be materially affected by changes in our assumptions. 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 our natural gas production. See Note 4 to the Consolidated Financial Statements for a description of the fair value hierarchy. 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.

We believe derivative instruments are "critical accounting estimates" because our financial condition and results of operations can be significantly impacted by changes in the market value of our derivative instruments due to the volatility of both NYMEX natural gas prices and basis. Future results of operations for any quarterly or annual period could be materially affected by changes in our assumptions. Refer to Item 7A., "Quantitative and Qualitative Disclosures about Market Risk" for discussion of a hypothetical increase or decrease of 10% in the market price of natural gas.

Business Combinations. 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. 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. We are involved in various legal and regulatory proceedings that arise in the ordinary course of business. We record a liability for contingencies based on our assessment that a loss is probable and the amount of the loss can be reasonably estimated. We consider many factors in making these assessments, including historical experience and matter specifics. Estimates are developed in consultation with legal counsel and are based on an analysis of potential results. See Note 13 to the Consolidated Financial Statements.

We accrue a liability for asset retirement obligations based on an estimate of the amount and timing of settlement. For oil and gas wells, the fair value of our plugging and abandonment obligations is recorded at the time the obligation is incurred, which is typically at the time the well is spud. See Note 1 to the Consolidated Financial Statements.

We believe contingencies and asset retirement obligations are "critical accounting estimates" because we must assess the probability of loss related to contingencies and the expected amount and timing of asset retirement obligation settlement. In addition, we must determine the estimated present value of future liabilities. Future results of operations for any quarterly or annual period could be materially affected by changes in our assumptions. If we incur losses related to contingencies that are higher than we expect, we could incur additional costs to settle such obligations. 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. An estimate of the sensitivity to changes in our assumptions is not practicable given the numerous assumptions that can materially affect our estimates.