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Item 7. Management’s Discussion and Analysis

2022-02-10 compared with 2021-02-17 · 144 added, 173 removed, 234 unchanged (58% of the section changed)

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Consolidated Results of Operations

Net loss for 2020 was $967 million, $3.71 per diluted share, an improvement of $255 million compared to net loss for 2019 of $1,222 million, $4.79 per diluted share.

The variance was attributable primarily to decreased impairments, the gain on the Equitrans Share Exchange (defined and discussed in Note 5 to the Consolidated Financial Statements), decreased other operating expenses, decreased depreciation and depletion expense and decreased transportation and processing expense, partly offset by decreased operating revenues, increased interest expense and decreased dividend and other income.

Net loss attributable to EQT Corporation for 2021 was $1,156 million, $3.58 per diluted share, compared to net loss attributable to EQT Corporation for 2020 of $967 million, $3.71 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.

See "Sales Volumes 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 "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.

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Sales volume (MMcf) 1,746,317 1,418,774

NYMEX price ($/MMBtu) (a) $ 2.09 $ 2.63

NYMEX price ($/MMBtu) $ 3.97 $ 2.09

Btu uplift 0.20 0.11

Natural gas price ($/Mcf) $ 4.17 $ 2.20

Basis ($/Mcf) (b) $ (0.47) $ (0.28)

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

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

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Natural gas sales, including cash settled derivatives $ 4,153,221 $ 3,359,583

Natural gas liquids (NGLs), excluding ethane:

Sales volume (MMcfe) (c) 44,702 44,082

NGLs, excluding ethane:

Sales volume (MMcfe) (b) 64,202 44,702

Sales volume (Mbbl) 10,700 7,451

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

Average NGLs price, including cash settled derivatives ($/Bbl) $ 20.39 $ 25.82

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

NGLs sales $ 344,260 $ 151,877

Sales volume (MMcfe) (c) 29,489 23,748

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

Sales volume (Mbbl) 6,258 4,914

Price ($/Bbl) $ 8.85 $ 3.48

Cash settled derivatives (not designated as hedges) ($/Bbl) — 1.02

Average Ethane price, including cash settled derivatives ($/Bbl) $ 3.48 $ 7.18

Ethane sales $ 55,393 $ 17,085

Sales volume (MMcfe) (c) 4,827 4,932

Sales volume (MMcfe) (b) 9,750 4,827

Sales volume (Mbbl) 1,625 804

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Oil sales $ 92,334 $ 20,574

Total liquids sales volume (MMcfe) (c) 79,018 72,762

Total liquids sales volume (MMcfe) (b) 111,500 79,018

Total liquids sales volume (Mbbl) 18,583 13,169

Total liquids sales $ 491,987 $ 189,536

Total natural gas and liquids sales, including cash settled derivatives (d) $ 3,549,119 $ 4,057,729

Total natural gas and liquids sales, including cash settled derivatives (c) $ 4,645,208 $ 3,549,119

Total sales volume (MMcfe) 1,857,817 1,497,792

Average realized price ($/Mcfe) $ 2.50 $ 2.37

(a) Our volume weighted NYMEX natural gas price (actual average NYMEX natural gas price ($/MMBtu)) was $2.08 and $2.63 for the years ended December 31, 2020 and 2019, respectively.

(b) Basis represents the difference between the ultimate sales price for natural gas and the NYMEX natural gas price.

(d) 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.

(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.

Non-GAAP Financial Measures Reconciliation

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

Net marketing services and other primarily includes the costs of, and recoveries on, pipeline capacity releases.

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.

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Add (deduct):

Gain on derivatives not designated as hedges (400,214) (616,634)

Net cash settlements received on derivatives not designated as hedges 897,190 246,639

Premiums received for derivatives that settled during the period 1,630 19,676

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

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

Net marketing services and other (35,685) (8,330)

Adjusted operating revenues, a non-GAAP financial measure $ 4,645,208 $ 3,549,119

Total sales volumes (MMcfe) 1,497,792 1,507,896

Total sales volume (MMcfe) 1,857,817 1,497,792

Average realized price ($/Mcfe) $ 2.50 $ 2.37

Sales Volumes and Revenues

Sales Volume and Revenues

Years Ended December 31,

2021 2020 Change % Change

(Thousands, unless otherwise noted)

Sales volume by shale (MMcfe):

Marcellus (a) 1,314,801 1,270,352 3.5

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 volumes (b) 1,497,792 1,507,896 (0.7)

Average daily sales volumes (MMcfe/d) 4,092 4,131 (0.9)

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 $ 2,650,299 $ 3,791,414 (30.1)

Gain on derivatives not designated as hedges 400,214 616,634 (35.1)

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)

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

(a) Includes Upper Devonian wells.

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

Sales of natural gas, NGLs and oil.

Sales of natural gas, NGLs and oil decreased for 2020 compared to 2019 due to a lower average realized price and lower sales volumes.

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

For 2020 and 2019, we received $898.8 million and $266.3 million, respectively, of net cash settlements, including net premiums received, on derivatives not designated as hedges, which are included in average realized price but may not be included in operating revenues.

Sales volumes for 2020 decreased compared

to 2019 due primarily to our strategic decisions to temporarily curtail production beginning in May 2020 and ending in November 2020 (the Strategic Production Curtailments) which resulted in a decrease to sales volumes of approximately 46 Bcfe.

Sales volumes for 2020 also decreased compared to 2019 by 16 Bcfe as a result of the 2020 Divestitures (defined in Note 7 to the Consolidated Financial Statements).

These decreases were partly offset by operational efficiencies realized throughout the year from increased production up-time and positively impacted sales volumes as well as an increase of approximately 12 Bcfe due to the Chevron Acquisition.

Gain on derivatives not designated as hedges.

For 2020, we recognized a gain on derivatives not designated as hedges of $400.2 million compared to $616.6 million for 2019.

The gains for 2020 and 2019 were related primarily to decreases in the fair market value of our NYMEX swaps and options due to increases in NYMEX forward prices.

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.

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

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

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

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

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

For 2021 and 2020, we paid $2,091.0 million and received $897.2 million, respectively, of net cash settlements on derivatives 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.

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

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Years Ended December 31,

2021 2020 Change % Change

(Thousands, unless otherwise noted)

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Processing 188,201 135,476 52,725 38.9

Lease operating expenses (LOE), excluding production taxes 109,027 84,501 29.0

Lease operating expenses (LOE) 126,640 109,027 17,613 16.2

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

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Processing 0.10 0.09 0.01 11.1

LOE, excluding production taxes 0.07 0.06 16.7

LOE 0.07 0.07 — —

Production taxes 0.05 0.03 0.02 66.7

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Production depletion 0.89 0.92 (0.03) (3.3)

Gathering expense increased on an absolute and per Mcfe basis for 2020 compared to 2019 due to a higher gathering rate structure as a result of the Consolidated GGA (defined in Note 5 to the Consolidated Financial Statements ) , partly offset by lower gathered volumes as a result of the Strategic Production Curtailments.

We expect to realize fee relief and a lower gathering rate structure from the Consolidated GGA beginning on the Mountain Valley Pipeline in-service date.

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 decreased on an absolute and per Mcfe basis for 2020 compared to 2019 due primarily to released capacity on, and credits received from, the Texas Eastern Transmission Pipeline, partly offset by higher costs associated with additional capacity on the Tennessee Gas Pipeline.

LOE increased on an absolute and per Mcfe basis for 2020 compared to 2019 due primarily to higher repairs and maintenance costs as a result of our increased focus on optimizing production from currently producing wells as well as higher salt water disposal costs.

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

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

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

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

Production taxes.

Production taxes decreased on an absolute and per Mcfe basis for 2020 compared to 2019 due primarily to lower severance taxes and Pennsylvania impact fees as a result of lower commodity prices.

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

Selling, general and administrative.

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

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

Depreciation and depletion.

Production depletion decreased on an absolute and per Mcfe basis for 2020 compared to 2019 due primarily to a lower annual depletion rate and lower volumes.

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 compared to $35.9 million for 2019.

The decrease was due primarily to the impairment of intangible assets recognized in the third quarter of 2019 as described below, which decreased the amortization rate.

The intangible assets were fully amortized in November 2020.

Impairment/loss on sale/exchange of long-lived assets .

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 6 to the Consolidated Financial Statements) and $39.1 million related to asset sales (described in Note 7 to the Consolidated Financial Statements).

During the fourth quarter of 2019, we recorded impairment of long-lived assets of $1,124.4 million, of which $1,035.7 million was associated with our non-strategic assets located in the Ohio Utica and $88.7 million was associated with our Pennsylvania and West Virginia Utica assets.

The impairment was due primarily to depressed natural gas prices and changes in our development strategy.

During the third quarter of 2019, we recorded a loss on exchange of long-lived assets of $13.9 million related to the 2019 Asset Exchange Transaction (defined and discussed in Note 6 to the Consolidated Financial Statements).

See Note 1 to the Consolidated Financial Statements for a discussion of the 2019 impairment test.

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 (defined and discussed in Note 8 to the Consolidated Financial Statements) 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 non-operating receivables as a result of expected credit losses.

During the third quarter of 2019, we recognized impairment of $15.4 million of intangible assets associated with non-compete agreements for former Rice Energy Inc.

executives who are now our employees.

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.

Impairment and expiration of leases for 2020 was $306.7 million compared to $556.4 million for 2019.

The decrease was driven by increased lease expirations in 2019 due to our change in strategic focus to core development opportunities as well as changes in market conditions.

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 of $28.5 million in 2020 were related primarily to transactions, changes in legal reserves, including settlements and reorganization.

Other operating expenses of $199.4 million in 2019 were related primarily to reorganization, due to reductions in workforce, which resulted in the recognition of severance and other termination benefits, changes in legal reserves, including settlements, contract terminations and the proxy contest.

See Note 1 to the Consolidated Financial Statements.

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 as described in Note 5 to the Consolidated Financial Statements.

Loss on investment in Equitrans Midstream Corporation.

Our investment in Equitrans Midstream is recorded at fair value by multiplying the closing stock price of Equitrans Midstream's common stock by the number of shares of Equitrans Midstream's common stock that we own.

Changes in fair value are recorded in loss on investment in Equitrans Midstream Corporation in the Statements of Consolidated Operations.

Our investment in Equitrans Midstream fluctuates with changes in Equitrans Midstream's stock price, which was $8.04 and $13.36 as of December 31, 2020 and 2019, respectively.

Note, the effect of the sale of 50% of our shares of Equitrans Midstream's common stock was recorded as a reduction to the investment in Equitrans Midstream in conjunction with our recognition of the gain on the 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.

(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.

Dividend and other income.

The decrease in 2020 as compared to 2019 is due primarily to lower dividends received from our investment in Equitrans Midstream driven by the decrease in the number of shares of Equitrans Midstream's common stock that we own.

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 2020, we recognized a loss on debt extinguishment 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 (defined and discussed in Note 10 to the Consolidated Financial Statements).

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.

Interest expense.

Interest expense increased for 2020 compared to 2019 due to increased interest incurred on new debt issued in 2020 as well as interest incurred on letters of credit issued in 2020.

These increases were partly offset by lower interest incurred due to the repayment of all or a portion of our 8.125% senior notes, 4.875% senior notes, floating rate notes and 2.50% senior notes and decreased borrowings on our credit facility.

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.

See Note 10 to the Consolidated Financial Statements.

The adjusted interest rate under the Adjustable Rate Notes (defined and discussed in Note 10 to the Consolidated Financial Statements) cannot exceed 2% of the original interest rate first set forth on the face of the Adjustable Rate Notes;

however, if our credit ratings improve, the interest rate under the Adjustable Rate Notes could be reduced to as low as the original interest rate set forth on the face of the Adjustable Rate Notes.

Income tax benefit.

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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, 2020 were $24.8 billion, composed of $1.3 billion in 2021, $1.7 billion in 2022, $1.8 billion in 2023, $1.9 billion in 2024, $1.8 billion in 2025 and $16.3 billion primarily in 2026 through 2042.

We also have commitments to purchase equipment, materials, frac sand for use as a proppant in our hydraulic fracturing operations and minimum volume commitments associated with certain water agreements.

As of December 31, 2020, future commitments under these contracts were $96.5 million in 2021 and $14.3 million in 2022.

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.

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 including the timing of 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 in Note 9 to the Consolidated Financial Statements, we had a total reserve for unrecognized tax benefits at December 31, 2020 of $181.2 million, of which $90.3 million is offset against deferred tax assets for general business tax credit carryforwards and NOLs.

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.

Planned Capital Expenditures.

In 2021, we expect to spend approximately $1.1 to $1.2 billion in total capital expenditures, excluding amounts attributable to noncontrolling interests.

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.

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.

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and drilling, completion and acquisition costs.

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

Operating Activities

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

The decrease was due primarily to lower cash operating revenues and unfavorable timing of working capital payments, partly offset by increased cash settlements received on derivatives not designated as hedges, income tax refunds, plus interest, received of $440 million during 2020 and lower cash operating expenses.

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.

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

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

The decrease was due to lower capital expenditures as a result of our change in strategic focus from production growth to capital efficiency as well as cash received from asset sales and the Equitrans Share Exchange.

The decrease was partly offset by cash paid for acquisitions as described in Note 6 .

The increase 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.

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Total capital expenditures 1,104 1,079

(Deduct) add non-cash items (b) (37) (171)

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

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

(a) Capital expenditures attributable to noncontrolling interests were $4.9 million for the year ended December 31, 2020.

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

The impact of accrued capital expenditures includes the reversal of the prior period accrual as well as the current period estimate.

(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.

(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 provided by financing activities was $32 million for 2020 compared to net cash used in financing activities of $249 million for 2019.

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

For 2019, the primary uses of financing cash flows were net repayments of debt and credit facility borrowings, and the primary source of financing cash flows was net proceeds from borrowings on the Term Loan Facility.

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

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 March 26, 2020, we announced the suspension of our quarterly cash dividend on our common stock for purposes of accelerating cash flow to be used for our Deleveraging Plan.

On February 3, 2022, our Board of Directors declared a quarterly cash dividend of $0.125 per share, payable on March 1, 2022, to shareholders of record at the close of business on February 14, 2022.

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.

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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 further discussion of what is deemed investment grade.

See Note 3 to the Consolidated Financial Statements for a description of what is deemed investment grade.

Rating agency Senior notes Outlook

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

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

Fitch Ratings Service (Fitch) BB Positive

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 the Adjustable Rate Notes, 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 hedging counterparties.

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.

As of February 4, 2022, 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 4, 2022, such assurances could be up to approximately $1.1 billion, inclusive of letters of credit, OTC derivative instrument margin deposits and other collateral posted of approximately $0.8 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.

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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 income.

As of December 31, 2020, we were in compliance with all debt provisions and covenants.

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

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

As of December 31, 2021, 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.

Commodity Risk Management

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

following table summarizes the approximate volumes and prices of our NYMEX hedge positions through 2024 as of February 12, 2021.

2021 (a) 2022 2023 2024

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

Q1 2022 (a) Q2 2022 Q3 2022 Q4 2022 2023 2024

Hedged Volume (MMDth) 355 329 287 287 858 16

Hedged Volume (MMDth/d) 3.9 3.6 3.1 3.1 2.4 —

Swaps (includes Futures)

Volume (MMDth) 289 296 254 232 166 2

Average Price ($/Dth) $ 2.71 $ 2.66 $ 2.48 $ 2.67

Price ($/Dth) $ 2.78 $ 2.63 $ 2.41 $ 2.36 $ 2.53 $ 2.67

Calls - Net Short

Volume (MMDth) 57 101 102 102 606 15

Average Short Strike Price ($/Dth) $ 2.91 $ 2.89 $ 2.89 $ 3.11

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

Puts - Net Long

Volume (MMDth) 65 32 32 54 689 15

Average Long Strike Price ($/Dth) $ 2.59 $ 2.35 $ 2.40 $ 2.45

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

Fixed Price Sales (b)

Volume (MMDth) 1 1 1 1 3 —

Average Price ($/Dth) $ 2.50 $ 2.38 $ 2.38 $ —

(a) Full year 2021.

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

For 2021, 2022, 2023 and 2024, we have natural gas sales agreements for approximately 18 MMDth, 18 MMDth, 88 MMDth and 11 MMDth, respectively, that include average NYMEX ceiling prices of $3.17, $3.17, $2.84 and $3.21, respectively.

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

(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.

We may use other contractual agreements to implement our commodity hedging strategy from time to time.

During 2020, we purchased $47 million of net options with the primary purpose of reducing future NYMEX based payments that could be due in 2021, 2022 and 2023 to Equitrans Midstream related to the Henry Hub Cash Bonus (defined and discussed in Note 5 to the Consolidated Financial Statements) provided for by the Consolidated GGA.

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.

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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 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, NGL and Oil Producing Activities.

Accounting for Gas, NGLs and Oil Producing Activities.

We use the successful efforts method of accounting for our oil and gas producing activities.

The carrying values of our proved oil and gas properties are reviewed for impairment when events or circumstances indicate that the remaining carrying value may not be recoverable.

To determine whether impairment of our oil and gas properties has occurred, we compare the estimated expected undiscounted future cash flows to the carrying values of those properties.

Estimated future cash flows are based on proved and, if determined reasonable by management, risk-adjusted probable reserves and assumptions generally consistent with the assumptions used by us for internal planning and budgeting purposes, including, among other things, the intended use of the asset, anticipated production from reserves, future market prices for natural gas, NGLs and oil adjusted for basis differentials, future operating costs and inflation.

Proved oil and gas properties that have carrying amounts in excess of estimated future undiscounted cash flows are written down to fair value, which is estimated by discounting the estimated future cash flows using discount rates and other assumptions that marketplace participants would use in their fair value estimates.

Capitalized costs of unproved oil and gas properties are evaluated for recoverability on a prospective basis at least annually.

Indicators of potential impairment include changes due to economic factors, potential shifts in business strategy and historical experience.

The likelihood of an impairment of unproved oil and gas properties increases as the expiration of a lease term approaches and drilling activity has not commenced.

If we do not intend to drill on the property prior to expiration of the lease or do not have the intent and ability to extend, renew, trade or sell the lease prior to expiration, impairment expense is recorded.

We believe accounting for gas, NGL 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.

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.

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 our impairments of proved and unproved oil and gas properties.

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.

Oil and Gas Reserves.

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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 volumes of reserves could have an impact on the depletion rate calculation and our Consolidated Financial Statements.

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.

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

We have recorded deferred tax assets resulting from federal and state NOL carryforwards, an AMT credit carryforward, other federal tax credit carryforwards, unrealized capacity contract losses, incentive compensation and investments in securities.

We have established a valuation allowance against a portion of the deferred tax assets related primarily to federal and state NOL carryforwards and our investment in Equitrans Midstream because we believe it is more likely than not that those deferred tax assets will not be fully realized.

We established a valuation allowance against the state and part of the federal deferred tax asset related to our investment in Equitrans Midstream because the fair value loss is not expected to be fully realized for tax purposes due to capital loss limitations.

No other significant valuation allowances have been established as we believe that future sources of taxable income, reversing temporary differences and other tax planning strategies will be sufficient to realize the deferred tax assets.

Changes to our valuation allowance would impact our income tax expense and net income in the period in which such a determination is made.

We estimate the amount of financial statement benefit recorded for uncertain tax positions.

See Note 9 to our Consolidated Financial Statements.

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.

When evaluating whether or not a valuation allowance should be established, we exercise judgment on whether it is more likely than not (a likelihood of more than 50%) that a portion or all of the deferred tax assets will not be realized.

To determine whether a valuation allowance is needed, we consider all available evidence, both positive and negative, including carrybacks, tax planning strategies, reversals of deferred tax assets and liabilities and forecasted future taxable income.

To determine the amount of financial statement benefit recorded for uncertain tax positions, we consider the amounts and probabilities of outcomes that could be realized upon ultimate settlement of an uncertain tax position using facts, circumstances and information available at the reporting date.

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.

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

We estimate the fair value of our financial instruments using quoted market prices when available.

If quoted market prices are not available, the fair value is based on models that use market-based parameters, including forward curves, discount rates, volatilities and nonperformance risk, as inputs.

Nonperformance risk considers the effect of our credit standing on the fair value of liabilities and the effect of the counterparty's credit standing on the fair value of assets.

We estimate nonperformance risk by analyzing publicly available market information, including a comparison of the yield on debt instruments with credit ratings similar to our credit rating or the counterparty's credit rating and the yield on a risk-free instrument.

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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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.

Contingencies and Asset Retirement Obligations.

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Estimates are developed in consultation with legal counsel and are based on an analysis of potential results.

See Note 16 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.

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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.

The rate relief was effected through the execution the Consolidated GGA (defined and discussed in Note 5 to the Consolidated Financial Statements).

We recorded a contract asset representing the estimated fair value of the rate relief provided by the Consolidated GGA.

Key assumptions used in the fair value calculation included an estimated production volume forecast, a market-based discount rate and a probability-weighted estimate of the in-service date of the Mountain Valley Pipeline.

Beginning with the Mountain Valley Pipeline in-service date, we will recognize amortization of the contract asset over a period of approximately four years in a manner consistent with the expected timing of our realization of the economic benefits of the rate relief provided by the Consolidated GGA.

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.

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Convertible Notes.

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

At issuance, we separated the Convertible Notes into liability and equity components.

The carrying amount of the liability component was calculated by measuring the fair value of similar debt instruments that do not have associated convertible features.

The carrying amount of the equity component, representing the conversion option, was determined by deducting the fair value of the liability component from the principal value of the Convertible Notes.

The equity component is not remeasured as long as it continues to meet the condition for equity classification.

The excess of the principal amount of the liability component over its carrying amount (the debt discount) will be amortized to interest expense over the term of the Convertible Notes using the effective interest rate method.

Issuance costs were allocated to the liability and equity components of the Convertible Notes based on their relative fair values.

In connection with the Convertible Notes offering, we entered into the Capped Call Transactions (defined and discussed in Note 10 to the Consolidated Financial Statements).

The Capped Call Transactions are separate from the Convertible Notes.

The Capped Call Transactions were recorded in shareholders' equity and were not accounted for as derivatives.

The cost to purchase the Capped Call Transactions was recorded as a reduction to equity and will not be remeasured.

Upon conversion of the Convertible Notes, we intend to use a combined settlement approach to satisfy our settlement obligation by paying or delivering to holders of the Convertible Notes cash equal to the principal amount of the obligation and EQT common stock for amounts that exceed the principal amount of the obligation.

As such, we used the treasury stock method for the diluted earnings per share (EPS) calculation, and there is no adjustment to the diluted EPS numerator for the cash-settled portion of the instrument.

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.

Business Combinations.

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

In the fourth quarter of 2020, we completed the Chevron Acquisition.

The most significant assumptions used in accounting for the Chevron Acquisition include those used to estimate the fair value of the oil and gas properties acquired, the acquired investment in midstream gathering assets and acquired contract liabilities.

We calculated the fair value of the acquired proved oil and gas properties, including in-process wells, using a risk-adjusted after-tax discounted cash flow analysis that was based on the following key assumptions:

future commodity prices, projections of estimated quantities of reserves, estimated future rates of production, projected reserve recovery factors, timing and amount of future development and operating costs and a weighted average cost of capital.

We calculated the fair value of the acquired unproved properties using the guideline transaction method that was based on the following key assumptions:

future development plans from a market participant perspective and value per undeveloped acre.

We calculated the fair value of our investment in the midstream gathering assets primarily using a discounted cash flow analysis that was based on the following key assumptions:

projected revenues, expenses and capital expenditures.

We calculated the fair value of acquired contract liabilities using estimated future volumes and annual contract commitments calculated on a discounted basis that was based on the following key assumptions:

estimated future volumes and market participant cost of debt.

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.

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