Exhibit 99.1
TABLE OF CONTENTS
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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 loss attributable to EQT Corporation for 2021 was $1,143 million, $3.54 per diluted share, compared to net loss attributable to EQT Corporation for 2020 of $959 million, $3.68 per diluted share. The change was attributable primarily to the loss on derivatives not designated as hedges, increased depreciation and depletion, increased transportation and processing and the gain on the Equitrans Share Exchange (defined and discussed in Note 5 to the Consolidated Financial Statements) recognized in the first quarter of 2020, partly offset by increased sales of natural gas, NGLs and oil, the income from investments, higher income tax benefit and the gain on sale/exchange of long-lived assets.
Results of operations for 2021 include the results of approximately six months of our operation of assets acquired in the Alta Acquisition, which closed in July 2021, the results of a full year of our operation of assets acquired from Chevron U.S.A. Inc. (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.
Net loss attributable to EQT Corporation for 2020 was $959 million, $3.68 per diluted share, compared to net loss attributable to EQT Corporation for 2019 of $1,222 million, $4.79 per diluted share. The variance was attributable primarily to decreased impairments, the gain on the Equitrans Share Exchange (defined and discussed in Note 5 to the Consolidated Financial Statements), decreased other operating expenses, decreased depreciation and depletion expense and decreased transportation and processing expense, partly offset by decreased operating revenues, increased interest expense and decreased dividend and other income.
See Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations" included in our Annual Report on Form 10-K for the year ended December 31, 2020, which is incorporated herein by reference, for discussion and analysis of consolidated results of operations for the year ended December 31, 2019.
See "Sales Volume and Revenues" and "Operating Expenses" for discussions of items affecting operating income and "Other Income Statement Items" for a discussion of other income statement items. See "Investing Activities" under "Capital Resources and Liquidity" for a discussion of capital expenditures.
Average Realized Price Reconciliation
The following table presents detailed natural gas and liquids operational information to assist in the understanding of our consolidated operations, including the calculation of our average realized price ($/Mcfe), which is based on adjusted operating revenues, a non-GAAP supplemental financial measure. Adjusted operating revenues is presented because it is an important measure we use to evaluate period-to-period comparisons of earnings trends. 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.
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Years Ended December 31, | |||||||||||
2021 | 2020 | ||||||||||
(Thousands, unless otherwise noted) | |||||||||||
NATURAL GAS | |||||||||||
Sales volume (MMcf) | 1,746,317 | 1,418,774 | |||||||||
NYMEX price ($/MMBtu) | $ | 3.97 | $ | 2.09 | |||||||
Btu uplift | 0.20 | 0.11 | |||||||||
Natural gas price ($/Mcf) | $ | 4.17 | $ | 2.20 | |||||||
Basis ($/Mcf) (a) | $ | (0.63) | $ | (0.47) | |||||||
Cash settled basis swaps not designated as hedges ($/Mcf) | (0.07) | 0.05 | |||||||||
Average differential, including cash settled basis swaps ($/Mcf) | $ | (0.70) | $ | (0.42) | |||||||
Average adjusted price ($/Mcf) | $ | 3.47 | $ | 1.78 | |||||||
Cash settled derivatives not designated as hedges ($/Mcf) | (1.09) | 0.59 | |||||||||
Average natural gas price, including cash settled derivatives ($/Mcf) | $ | 2.38 | $ | 2.37 | |||||||
Natural gas sales, including cash settled derivatives | $ | 4,153,221 | $ | 3,359,583 | |||||||
LIQUIDS | |||||||||||
NGLs, excluding ethane: | |||||||||||
Sales volume (MMcfe) (b) | 64,202 | 44,702 | |||||||||
Sales volume (Mbbl) | 10,700 | 7,451 | |||||||||
Price ($/Bbl) | $ | 44.50 | $ | 20.51 | |||||||
Cash settled derivatives not designated as hedges ($/Bbl) | (12.32) | (0.12) | |||||||||
Average price, including cash settled derivatives ($/Bbl) | $ | 32.18 | $ | 20.39 | |||||||
NGLs sales | $ | 344,260 | $ | 151,877 | |||||||
Ethane: | |||||||||||
Sales volume (MMcfe) (b) | 37,548 | 29,489 | |||||||||
Sales volume (Mbbl) | 6,258 | 4,914 | |||||||||
Price ($/Bbl) | $ | 8.85 | $ | 3.48 | |||||||
Ethane sales | $ | 55,393 | $ | 17,085 | |||||||
Oil: | |||||||||||
Sales volume (MMcfe) (b) | 9,750 | 4,827 | |||||||||
Sales volume (Mbbl) | 1,625 | 804 | |||||||||
Price ($/Bbl) | $ | 56.82 | $ | 25.57 | |||||||
Oil sales | $ | 92,334 | $ | 20,574 | |||||||
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 | |||||||||||
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)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.
Years Ended December 31, | |||||||||||
2021 | 2020 | ||||||||||
(Thousands, unless otherwise noted) | |||||||||||
Total operating revenues | $ | 3,064,663 | $ | 3,058,843 | |||||||
Add (deduct): | |||||||||||
Loss (gain) on derivatives not designated as hedges | 3,775,042 | (400,214) | |||||||||
Net cash settlements (paid) received on derivatives not designated as hedges | (2,091,003) | 897,190 | |||||||||
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 volume (MMcfe) | 1,857,817 | 1,497,792 | |||||||||
Average realized price ($/Mcfe) | $ | 2.50 | $ | 2.37 |
Sales Volume and Revenues
Years Ended December 31, | |||||||||||||||||||||||
2021 | 2020 | Change | % Change | ||||||||||||||||||||
(Thousands, unless otherwise noted) | |||||||||||||||||||||||
Sales volume by shale (MMcfe): | |||||||||||||||||||||||
Marcellus | 1,684,673 | 1,314,801 | 369,872 | 28.1 | |||||||||||||||||||
Ohio Utica | 163,775 | 177,864 | (14,089) | (7.9) | |||||||||||||||||||
Other | 9,369 | 5,127 | 4,242 | 82.7 | |||||||||||||||||||
Total sales volume | 1,857,817 | 1,497,792 | 360,025 | 24.0 | |||||||||||||||||||
Average daily sales volume (MMcfe/d) | 5,090 | 4,092 | 998 | 24.4 | |||||||||||||||||||
Operating revenues: | |||||||||||||||||||||||
Sales of natural gas, 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 |
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Sales of natural gas, NGLs and oil. Sales of natural gas, NGLs and oil increased for 2021 compared to 2020 due to increased sales volume and a higher average realized price.
Sales volume increased primarily as a result of sales volume increases of 170 Bcfe from the assets acquired in the Alta Acquisition, sales volume increases of 127 Bcfe from the assets acquired in the Chevron Acquisition, prior year sales volume decreases of 46 Bcfe from the 2020 Strategic Production Curtailments and sales volume increases as a result of the Reliance Asset Acquisition and from wells turned in-line during 2021, partly offset by sales volume decreases 9 Bcfe from the 2020 Divestiture (defined in Note 8 to the Consolidated Financial Statements).
The 2020 Strategic Production Curtailments refers to our strategic decisions to temporarily curtail 2020 production. 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.
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Operating Expenses
The following table presents information on our production-related operating expenses.
Years Ended December 31, | |||||||||||||||||||||||
2021 | 2020 | Change | % Change | ||||||||||||||||||||
(Thousands, unless otherwise noted) | |||||||||||||||||||||||
Operating expenses: | |||||||||||||||||||||||
Gathering | $ | 1,228,153 | $ | 1,068,590 | $ | 159,563 | 14.9 | ||||||||||||||||
Transmission | 525,811 | 506,668 | 19,143 | 3.8 | |||||||||||||||||||
Processing | 188,201 | 135,476 | 52,725 | 38.9 | |||||||||||||||||||
Lease operating expenses (LOE) | 126,640 | 109,027 | 17,613 | 16.2 | |||||||||||||||||||
Production taxes | 98,639 | 46,376 | 52,263 | 112.7 | |||||||||||||||||||
Exploration | 24,403 | 5,484 | 18,919 | 345.0 | |||||||||||||||||||
Selling, general and administrative | 196,315 | 174,769 | 21,546 | 12.3 | |||||||||||||||||||
Production depletion | $ | 1,658,113 | $ | 1,375,542 | $ | 282,571 | 20.5 | ||||||||||||||||
Other depreciation and depletion | 18,589 | 17,923 | 666 | 3.7 | |||||||||||||||||||
Total depreciation and depletion | $ | 1,676,702 | $ | 1,393,465 | $ | 283,237 | 20.3 | ||||||||||||||||
Per Unit ($/Mcfe): | |||||||||||||||||||||||
Gathering | $ | 0.66 | $ | 0.71 | $ | (0.05) | (7.0) | ||||||||||||||||
Transmission | 0.28 | 0.34 | (0.06) | (17.6) | |||||||||||||||||||
Processing | 0.10 | 0.09 | 0.01 | 11.1 | |||||||||||||||||||
LOE | 0.07 | 0.07 | — | — | |||||||||||||||||||
Production taxes | 0.05 | 0.03 | 0.02 | 66.7 | |||||||||||||||||||
Exploration | 0.01 | — | 0.01 | 100.0 | |||||||||||||||||||
Selling, general and administrative | 0.11 | 0.12 | (0.01) | (8.3) | |||||||||||||||||||
Production depletion | 0.89 | 0.92 | (0.03) | (3.3) |
Gathering. 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.
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Selling, general and administrative. Selling, general and administrative expense increased on an absolute basis for 2021 compared to 2020 due primarily to higher long-term incentive compensation costs as a result of changes in the fair value of awards as well as higher litigation expense. Selling, general and administrative expense decreased on a per Mcfe basis for 2021 compared to 2020 due primarily to increased sales volumes and nominal incremental selling, general and administrative spend with respect to the Alta Acquisition and Chevron Acquisition.
Depreciation and depletion. Production depletion expense increased on an absolute basis for 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 (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 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.
(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. Dividend and other income decreased for 2021 compared to 2020 due primarily to lower dividends received from our investment in Equitrans Midstream driven by a decrease in the number of shares of Equitrans Midstream's common stock that we owned as well as a decrease in the dividend amount per share.
Loss on debt extinguishment. During 2021, we recognized a loss on debt extinguishment of $9.8 million due to fees incurred for a bridge-loan commitment related to the Alta Acquisition and the repayment of our 4.875% senior notes. During 2020, we recognized a loss on debt extinguishment of $25.4 million related to the repayment of all or a portion of our 4.875% senior notes, 2.50% senior notes, 3.00% senior notes, floating rate notes and term loan facility. See Note 10 to the Consolidated Financial Statements.
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Interest expense. Interest expense increased for 2021 compared to 2020 due to increased interest incurred on new debt related to the Chevron Acquisition and Alta Acquisition and higher periodic borrowings under our credit facility. See Note 10 to the Consolidated Financial Statements.
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. 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. See Note 9 to the Consolidated Financial Statements.
Impairment of Oil and Gas Properties
See "Critical Accounting Policies and Estimates" and Note 1 to the Consolidated Financial Statements for a discussion of our accounting policies and significant assumptions related to impairment of our oil and gas properties. See 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. 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 of the contractual commitments under our debt agreements, including the timing of principal repayments.
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Unrecognized Tax Benefits. As discussed further in Note 9 to the Consolidated Financial Statements, as of December 31, 2021, we had a total reserve for unrecognized tax benefits of $94.1 million and an additional reserve of $97.2 million that was offset against deferred tax assets for general business tax credit carryforwards and NOLs. We are currently unable to make reasonably reliable estimates of the period of cash settlement of these potential liabilities with taxing authorities.
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. We could choose to defer a portion of these planned 2022 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. 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 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. 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 $2,073 million for 2021 compared to $1,556 million for 2020. The increase was due primarily to higher cash paid for acquisitions and proceeds from the sale of assets in 2020.
The following table summarizes our capital expenditures.
Years Ended December 31, | |||||||||||
2021 | 2020 | ||||||||||
(Millions) | |||||||||||
Reserve development | $ | 828 | $ | 839 | |||||||
Land and lease (a) | 144 | 121 | |||||||||
Capitalized overhead | 58 | 51 | |||||||||
Capitalized interest | 18 | 17 | |||||||||
Other production infrastructure | 47 | 40 | |||||||||
Other corporate items | 9 | 11 | |||||||||
Total capital expenditures | 1,104 | 1,079 | |||||||||
Deduct: Non-cash items (b) | (49) | (37) | |||||||||
Total cash capital expenditures | $ | 1,055 | $ | 1,042 |
(a)Capital expenditures attributable to noncontrolling interest were $9.6 million and $4.9 million for the years ended December 31, 2021 and 2020, respectively.
(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 $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
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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 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. The amounts involved in any such transactions may be material. Additionally, we plan to dispose of our remaining retained shares of Equitrans Midstream's common stock and use the proceeds to reduce our debt.
See Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations" included in our Annual Report on Form 10-K for the year ended December 31, 2020, which is incorporated herein by reference, for discussion and analysis of operating, investing and financing activities for the year ended December 31, 2019.
Security Ratings and Financing Triggers
The table below reflects the credit ratings and rating outlooks assigned to our debt instruments at February 4, 2022. 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.
Rating agency | Senior notes | Outlook | ||||||||||||
Moody's Investors Service (Moody's) | Ba1 | Stable | ||||||||||||
Standard & Poor's Ratings Service (S&P) | BB+ | Positive | ||||||||||||
Fitch Ratings Service (Fitch) | BB+ | Stable |
Changes in credit ratings may affect our access to the capital markets, the cost of short-term debt through interest rates and fees under our lines of credit, the interest rate on our senior notes with adjustable rates, the rates available on new long-term debt, our pool of investors and funding sources, the borrowing costs and margin deposit requirements on our OTC derivative instruments and credit assurance requirements, including collateral, in support of our midstream service contracts, joint venture arrangements or construction contracts. 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 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.
Our debt agreements and other financial obligations contain various provisions that, if not complied with, could result in default or event of default under our credit facility, mandatory partial or full repayment of amounts outstanding, reduced loan capacity or other similar actions. The most significant covenants and events of default under the debt agreements relate to maintenance of a debt-to-total capitalization ratio, limitations on transactions with affiliates, insolvency events, nonpayment of scheduled principal or interest payments, acceleration of other financial obligations and change of control provisions. Our credit facility contains financial covenants that require us to have a total debt-to-total capitalization ratio no greater than 65%. The calculation
11
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
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 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 | ||||||||||||||||||||||||||||||||
Avg. 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 | ||||||||||||||||||||||||||||||||
Avg. 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 | ||||||||||||||||||||||||||||||||
Avg. 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 | — | ||||||||||||||||||||||||||||||||
Avg. 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.
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
See Note 17 to the Consolidated Financial Statements for a discussion of our guarantees.
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Commitments and Contingencies
In the ordinary course of business, various legal and regulatory claims and proceedings are pending or threatened against us. While the amounts claimed may be substantial, we are unable to predict with certainty the ultimate outcome of such claims and proceedings. We accrue legal and other direct costs related to loss contingencies when actually incurred. We have established reserves that we believe to be appropriate for pending matters and, after consultation with counsel and giving appropriate consideration to available insurance, we believe that the ultimate outcome of any matter currently pending against us will not materially affect our financial condition, results of operations or liquidity. See Note 16 to the Consolidated Financial Statements for a discussion of our commitments and contingencies. See Item 3., "Legal Proceedings."
Recently Issued Accounting Standards
Our recently issued accounting standards are described in Note 1 to the Consolidated Financial Statements.
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 gas, NGLs and oil producing activities is a "critical accounting estimate" because the evaluations of impairment of proved properties involve significant judgment about future events, such as future sales prices of natural gas and NGLs and future production costs, as well as the amount of natural gas and NGLs recorded and timing of recoveries. Significant changes in these estimates could result in the costs of our proved and unproved properties not being recoverable; therefore, we would be required to recognize impairment. See "Impairment of Oil and Gas Properties" and Note 1 to the Consolidated Financial Statements for additional information on impairments of our proved and unproved oil and gas properties.
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 future statutory tax rates and tax deductions and credits available under current laws.
13
We believe oil and gas reserves is a "critical accounting estimate" because we must periodically reevaluate proved reserves along with estimates of future production rates, production costs and the timing of development expenditures. Future results of operations and the strength of our Consolidated Balance Sheet for any quarterly or annual period could be materially affected by changes in our assumptions. Significant changes in these estimates could result in a change to our estimated reserves, which could lead to a material change to our production depletion expense. See "Impairment of Oil and Gas Properties" for additional information on our oil and gas reserves.
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.
Derivative Instruments. We enter into derivative commodity instrument contracts primarily to reduce exposure to commodity price risk associated with future sales of natural gas production. 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.
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.
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 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. 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.
14
Contract Asset. In the first quarter of 2020, we entered into two share purchase agreements with Equitrans Midstream to sell to Equitrans Midstream 50% of our ownership of Equitrans Midstream's common stock in exchange for a combination of cash and rate relief under certain of our gathering agreements with EQM, an affiliate of Equitrans Midstream. See Note 5 to the Consolidated Financial Statements for further discussion of the key assumptions used in the fair value calculation of the contract asset and Note 1 to the Consolidated Financial Statements for a discussion of impairment considerations.
We believe the Consolidated GGA contract asset is a "critical accounting estimate" because the assumptions used in the valuation of the contract asset involved significant judgment. Future results of operations for any quarterly or annual period could be materially affected by changes in our assumptions. A change in the estimated production volume forecast, the market-based discount rate or the probability-weighted estimate of the in-service date of the Mountain Valley Pipeline could have resulted in a change in the valuation of the contract asset.
Convertible Notes. In the second quarter of 2020, we issued the Convertible Notes and Capped Call Transactions (each defined and discussed in Note 10 to the Consolidated Financial Statements). See Note 10 to the Consolidated Financial Statements for a discussion of our 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 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.
15
Item 8. Financial Statements and Supplementary Data
Page Reference | ||||||||
16
Report of Independent Registered Public Accounting Firm
To the Shareholders and the Board of Directors of EQT Corporation
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of EQT Corporation and subsidiaries (the Company) as of December 31, 2021 and 2020, the related statements of consolidated operations, comprehensive loss, cash flows and equity for each of the three years in the period ended December 31, 2021, and the related notes and the financial statement schedule listed in the Index at Item 15(a) (collectively referred to as the "consolidated financial statements"). In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of the Company at December 31, 2021 and 2020, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated February 10, 2022 expressed an unqualified opinion thereon.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
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Depreciation, depletion and amortization ('DD&A') of proved oil and natural gas properties
Description of the Matter | At December 31, 2021, the net book value of the Company's proved oil and natural gas properties was $15,610 million, and depreciation, depletion and amortization (DD&A) expense was $1,677 million for the year then ended. As described in Note 1, under the successful efforts method of accounting, DD&A is recorded on a cost center basis using the units-of-production method. Proved developed reserves, as estimated by the Company's internal engineers, are used to calculate depreciation of wells and related equipment and facilities and amortization of intangible drilling costs. Total proved reserves, also estimated by the Company's engineers, are used to calculate depletion on property acquisitions. Proved natural gas, natural gas liquids (NGLs) and oil reserve estimates are based on geological and engineering evaluations of in-place hydrocarbon volumes. Significant judgment is required by the Company's engineers in evaluating geological and engineering data when estimating proved natural gas, NGLs and oil reserves. Estimating reserves also requires the selection of inputs, including natural gas, NGLs and oil price assumptions, future operating and capital costs assumptions and tax rates by jurisdiction, among others. Because of the complexity involved in estimating natural gas, NGLs and oil reserves, management used independent engineers to audit the estimates prepared by the Company's internal engineers as of December 31, 2021. Auditing the Company's DD&A calculation is especially complex because of the use of the work of the internal engineers and the independent engineers and the evaluation of management's determination of the inputs described above used by the specialists in estimating proved natural gas, NGLs and oil reserves. | ||||
How We Addressed the Matter in Our Audit | We obtained an understanding, evaluated the design and tested the operating effectiveness of the Company's controls over its process to calculate DD&A, including management’s controls over the completeness and accuracy of the financial data provided to the specialists for use in estimating the proved natural gas, NGLs and oil reserves. Our audit procedures included, among others, evaluating the professional qualifications and objectivity of the Company engineer primarily responsible for overseeing the preparation of the reserve estimates by the internal engineering staff and the independent engineers used to audit the estimates. In addition, we evaluated the completeness and accuracy of the financial data and inputs described above used by the specialists in estimating proved natural gas, NGLs and oil reserves by agreeing them to source documentation and we identified and evaluated corroborative and contrary evidence. For proved undeveloped reserves, we evaluated management's development plan for compliance with the SEC rule that undrilled locations are scheduled to be drilled within five years, unless specific circumstances justify a longer time, by assessing consistency of the development projections with the Company's drill plan and the availability of capital relative to the drill plan. We also tested the mathematical accuracy of the DD&A calculations, including comparing the proved natural gas, NGLs and oil reserves amounts used to the Company’s reserve report. |
18
Valuation of Acquired Natural Gas and Oil Properties
Description of the Matter | As described in Note 6 to the consolidated financial statements, on July 21, 2021, the Company completed the acquisition of Alta Marcellus Development, LLC and ARD Operating, LLC and subsidiaries. The Company's accounting for the acquisition included determining the fair value of the acquired natural gas and oil properties. The determination of fair value of the acquired natural gas and oil properties included significant judgment and assumptions by management, including future commodity prices, anticipated production volumes, future operating and development costs, and a weighted average cost of capital (WACC). Auditing the Company's valuation of acquired natural gas and oil properties involved a high degree of subjectivity as the determination of fair value was based on assumptions as described above about future market and economic conditions. In addition, certain of the assumptions developed by the Company’s internal engineers in conjunction with the reserve estimates described in the preceding critical audit matter are used as inputs in the cash flow model. | ||||
How We Addressed the Matter in Our Audit | We obtained an understanding, evaluated the design, and tested the operating effectiveness of controls over the Company's process to estimate fair value for the acquired natural gas and oil properties. For example, we tested controls over management's assessment of the appropriateness of the significant assumptions that are inputs to the fair value calculation and management’s review of the valuation model. Our audit procedures included, among others, evaluating the professional qualifications and objectivity of the Company engineer primarily responsible for overseeing the preparation of the reserve estimates by the internal engineering staff, the independent engineers used to audit the estimates, and the external valuation specialist used to assist with the determination of the fair value of certain acquired assets. Our testing of the Company’s estimate of fair value of the acquired natural gas and oil properties included, among other procedures, evaluating the significant assumptions used and testing the completeness and accuracy of the underlying data. The audit effort involved the use of our valuation specialists to assist in evaluating the appropriateness of the methodology used in the cash flow model, as well as testing the significant market-related assumptions described above used to develop the fair value estimate. We evaluated the reasonableness of management's assumptions by comparing the key market-related assumptions (including future natural gas prices and WACC rates) used in the cash flow model to external market and third-party data and anticipated production volumes to the reserve estimates audited by the independent engineers. |
/s/ Ernst & Young LLP
We have served as the Company's auditor since 1950.
Pittsburgh, Pennsylvania
February 10, 2022, except for Note 10, with respect to the effects of the Company's adoption of Accounting Standards Update No. 2020-06, as to which the date is April 28, 2022
19
EQT CORPORATION AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED OPERATIONS
YEARS ENDED DECEMBER 31,
2021 | 2020 | 2019 | |||||||||||||||
(Thousands, except per share amounts) | |||||||||||||||||
Operating revenues: | |||||||||||||||||
Sales of natural gas, natural gas liquids and oil | $ | 6,804,020 | $ | 2,650,299 | $ | 3,791,414 | |||||||||||
(Loss) gain on derivatives not designated as hedges | (3,775,042) | 400,214 | 616,634 | ||||||||||||||
Net marketing services and other | 35,685 | 8,330 | 8,436 | ||||||||||||||
Total operating revenues | 3,064,663 | 3,058,843 | 4,416,484 | ||||||||||||||
Operating expenses: | |||||||||||||||||
Transportation and processing | 1,942,165 | 1,710,734 | 1,752,752 | ||||||||||||||
Production | 225,279 | 155,403 | 153,785 | ||||||||||||||
Exploration | 24,403 | 5,484 | 7,223 | ||||||||||||||
Selling, general and administrative | 196,315 | 174,769 | 170,611 | ||||||||||||||
Depreciation and depletion | 1,676,702 | 1,393,465 | 1,538,745 | ||||||||||||||
Amortization of intangible assets | — | 26,006 | 35,916 | ||||||||||||||
(Gain) loss/impairment on sale/exchange of long-lived assets | (21,124) | 100,729 | 1,138,287 | ||||||||||||||
Impairment of intangible and other assets | — | 34,694 | 15,411 | ||||||||||||||
Impairment and expiration of leases | 311,835 | 306,688 | 556,424 | ||||||||||||||
Other operating expenses | 70,063 | 28,537 | 199,440 | ||||||||||||||
Total operating expenses | 4,425,638 | 3,936,509 | 5,568,594 | ||||||||||||||
Operating loss | (1,360,975) | (877,666) | (1,152,110) | ||||||||||||||
Gain on Equitrans Share Exchange (see Note 5) | — | (187,223) | — | ||||||||||||||
(Income) loss from investments | (71,841) | 314,468 | 336,993 | ||||||||||||||
Dividend and other income | (19,105) | (35,512) | (91,483) | ||||||||||||||
Loss on debt extinguishment | 9,756 | 25,435 | — | ||||||||||||||
Interest expense | 289,753 | 259,268 | 199,851 | ||||||||||||||
Loss before income taxes | (1,569,538) | (1,254,102) | (1,597,471) | ||||||||||||||
Income tax benefit | (428,037) | (295,293) | (375,776) | ||||||||||||||
Net loss | (1,141,501) | (958,809) | (1,221,695) | ||||||||||||||
Less: Net income (loss) attributable to noncontrolling interest | 1,246 | (10) | — | ||||||||||||||
Net loss attributable to EQT Corporation | $ | (1,142,747) | $ | (958,799) | $ | (1,221,695) | |||||||||||
Loss per share of common stock attributable to EQT Corporation: | |||||||||||||||||
Basic and diluted: | |||||||||||||||||
Weighted average common stock outstanding | 323,196 | 260,613 | 255,141 | ||||||||||||||
Net loss attributable to EQT Corporation | $ | (3.54) | $ | (3.68) | $ | (4.79) | |||||||||||
The accompanying notes are an integral part of these Consolidated Financial Statements.
20
EQT CORPORATION AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED COMPREHENSIVE LOSS
YEARS ENDED DECEMBER 31,
2021 | 2020 | 2019 | |||||||||||||||
(Thousands) | |||||||||||||||||
Net loss | $ | (1,141,501) | $ | (958,809) | $ | (1,221,695) | |||||||||||
Other comprehensive income (loss), net of tax: | |||||||||||||||||
Net change in interest rate cash flow hedges, net of tax: $210 in 2019 | — | — | 387 | ||||||||||||||
Other postretirement benefits liability adjustment, net of tax: $254, $(36) and $150 | 744 | (156) | 316 | ||||||||||||||
Change in accounting principle | — | — | (496) | ||||||||||||||
Other comprehensive income (loss) | 744 | (156) | 207 | ||||||||||||||
Comprehensive loss | (1,140,757) | (958,965) | (1,221,488) | ||||||||||||||
Less: Comprehensive income (loss) attributable to noncontrolling interest | 1,246 | (10) | — | ||||||||||||||
Comprehensive loss attributable to EQT Corporation | $ | (1,142,003) | $ | (958,955) | $ | (1,221,488) |
The accompanying notes are an integral part of these Consolidated Financial Statements.
21
EQT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31,
2021 | 2020 | ||||||||||
(Thousands) | |||||||||||
ASSETS | |||||||||||
Current assets: | |||||||||||
Cash and cash equivalents | $ | 113,963 | $ | 18,210 | |||||||
Accounts receivable (less provision for doubtful accounts: $321 and $6,239) | 1,438,031 | 566,552 | |||||||||
Derivative instruments, at fair value | 543,337 | 527,073 | |||||||||
Prepaid expenses and other | 191,435 | 103,615 | |||||||||
Total current assets | 2,286,766 | 1,215,450 | |||||||||
Property, plant and equipment | 26,016,092 | 21,995,249 | |||||||||
Less: Accumulated depreciation and depletion | 7,597,172 | 5,940,984 | |||||||||
Net property, plant and equipment | 18,418,920 | 16,054,265 | |||||||||
Contract asset | 410,000 | 410,000 | |||||||||
Other assets | 491,702 | 433,754 | |||||||||
Total assets | $ | 21,607,388 | $ | 18,113,469 | |||||||
LIABILITIES AND EQUITY | |||||||||||
Current liabilities: | |||||||||||
Current portion of debt | $ | 1,060,970 | $ | 154,161 | |||||||
Accounts payable | 1,339,251 | 705,461 | |||||||||
Derivative instruments, at fair value | 2,413,608 | 600,877 | |||||||||
Other current liabilities | 372,412 | 301,911 | |||||||||
Total current liabilities | 5,186,241 | 1,762,410 | |||||||||
Credit facility borrowings | — | 300,000 | |||||||||
Senior notes | 4,435,782 | 4,496,689 | |||||||||
Note payable to EQM Midstream Partners, LP | 94,320 | 99,838 | |||||||||
Deferred income taxes | 907,306 | 1,334,523 | |||||||||
Other liabilities and credits | 1,012,740 | 945,057 | |||||||||
Total liabilities | 11,636,389 | 8,938,517 | |||||||||
Equity: | |||||||||||
Common stock, no par value, shares authorized: 640,000, shares issued: 377,432 and 280,003 | 10,071,820 | 8,145,539 | |||||||||
Treasury stock, shares at cost: 1,033 and 1,658 | (18,046) | (29,348) | |||||||||
(Accumulated deficit) retained earnings | (94,400) | 1,056,626 | |||||||||
Accumulated other comprehensive loss | (4,611) | (5,355) | |||||||||
Total common shareholders' equity | 9,954,763 | 9,167,462 | |||||||||
Noncontrolling interest in consolidated subsidiaries | 16,236 | 7,490 | |||||||||
Total equity | 9,970,999 | 9,174,952 | |||||||||
Total liabilities and equity | $ | 21,607,388 | $ | 18,113,469 |
The accompanying notes are an integral part of these Consolidated Financial Statements.
22
EQT CORPORATION AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
YEARS ENDED DECEMBER 31,
2021 | 2020 | 2019 | |||||||||||||||
(Thousands) | |||||||||||||||||
Cash flows from operating activities: | |||||||||||||||||
Net loss | $ | (1,141,501) | $ | (958,809) | $ | (1,221,695) | |||||||||||
Adjustments to reconcile net loss to net cash provided by operating activities: | |||||||||||||||||
Deferred income tax benefit | (427,470) | (152,275) | (275,063) | ||||||||||||||
Depreciation and depletion | 1,676,702 | 1,393,465 | 1,538,745 | ||||||||||||||
Amortization of intangible assets | — | 26,006 | 35,916 | ||||||||||||||
Gain/loss/impairment on sale/exchange of long-lived assets and impairment and expiration of leases | 290,711 | 442,111 | 1,710,122 | ||||||||||||||
Gain on Equitrans Share Exchange | — | (187,223) | — | ||||||||||||||
(Income) loss from investments | (71,841) | 314,468 | 336,993 | ||||||||||||||
Loss on debt extinguishment | 9,756 | 25,435 | — | ||||||||||||||
Share-based compensation expense | 28,169 | 19,552 | 31,233 | ||||||||||||||
Amortization, accretion and other | 47,086 | 25,482 | 23,296 | ||||||||||||||
Loss (gain) on derivatives not designated as hedges | 3,775,042 | (400,214) | (616,634) | ||||||||||||||
Cash settlements (paid) received paid on derivatives not designated as hedges | (2,091,003) | 897,190 | 246,639 | ||||||||||||||
Net premiums (paid) received on derivative instruments | (66,495) | (46,665) | 22,616 | ||||||||||||||
Changes in other assets and liabilities: | |||||||||||||||||
Accounts receivable | (699,992) | (36,296) | 432,323 | ||||||||||||||
Accounts payable | 456,988 | (29,193) | (238,674) | ||||||||||||||
Income tax receivable and payable | (23,909) | 322,763 | (167,281) | ||||||||||||||
Other current assets | (75,100) | (68,628) | 54,776 | ||||||||||||||
Other items, net | (24,695) | (49,468) | (61,608) | ||||||||||||||
Net cash provided by operating activities | 1,662,448 | 1,537,701 | 1,851,704 | ||||||||||||||
Cash flows from investing activities: | |||||||||||||||||
Capital expenditures | (1,055,128) | (1,042,231) | (1,602,454) | ||||||||||||||
Cash paid for acquisitions, net of cash acquired (see Note 6) | (1,030,239) | (691,942) | — | ||||||||||||||
Proceeds from sale of assets | 2,452 | 126,080 | — | ||||||||||||||
Proceeds from sale/exchange of investment shares | 24,369 | 52,323 | — | ||||||||||||||
Other investing activities | (14,196) | (30) | 1,312 | ||||||||||||||
Net cash used in investing activities | (2,072,742) | (1,555,800) | (1,601,142) | ||||||||||||||
Cash flows from financing activities: | |||||||||||||||||
Net proceeds from issuance of common stock | — | 340,923 | — | ||||||||||||||
Proceeds from credit facility borrowings | 8,086,000 | 3,118,250 | 2,978,750 | ||||||||||||||
Repayment of credit facility borrowings | (8,386,000) | (3,112,250) | (3,484,750) | ||||||||||||||
Proceeds from issuance of debt | 1,000,000 | 2,600,000 | 1,000,000 | ||||||||||||||
Debt issuance costs and Capped Call Transactions (see Note 10) | (19,713) | (71,056) | (913) | ||||||||||||||
Repayment and retirement of debt | (154,336) | (2,822,262) | (704,661) | ||||||||||||||
Premiums paid on debt extinguishment | (9,599) | (21,132) | — | ||||||||||||||
Contributions from noncontrolling interest | 7,500 | 7,500 | — | ||||||||||||||
Dividends paid | — | (7,664) | (30,655) | ||||||||||||||
Cash paid for taxes related to net settlement of share-based incentive awards | (3,845) | (596) | (7,224) | ||||||||||||||
Repurchase and retirement of common stock | (12,922) | — | — | ||||||||||||||
Other financing activities | (1,038) | — | — | ||||||||||||||
Net cash provided by (used in) financing activities | 506,047 | 31,713 | (249,453) | ||||||||||||||
Net change in cash and cash equivalents | 95,753 | 13,614 | 1,109 | ||||||||||||||
Cash and cash equivalents at beginning of year | 18,210 | 4,596 | 3,487 | ||||||||||||||
Cash and cash equivalents at end of year | $ | 113,963 | $ | 18,210 | $ | 4,596 |
The accompanying notes are an integral part of these Consolidated Financial Statements.
See Note 1 for supplemental cash flow information.
23
EQT CORPORATION AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED EQUITY
YEARS ENDED DECEMBER 31, 2021, 2020 and 2019
Common Stock | Accumulated Other Comprehensive Loss | Noncontrolling Interest in Consolidated Subsidiaries | |||||||||||||||||||||||||||||||||||||||
Shares | No Par Value | Treasury Stock | Retained Earnings (Accumulated Deficit) | Total Equity | |||||||||||||||||||||||||||||||||||||
(Thousands, except per share amounts) | |||||||||||||||||||||||||||||||||||||||||
Balance at December 31, 2018 | 254,472 | $ | 7,828,554 | $ | (49,194) | $ | 3,184,275 | $ | (5,406) | $ | — | $ | 10,958,229 | ||||||||||||||||||||||||||||
Comprehensive (loss) income, net of tax: | |||||||||||||||||||||||||||||||||||||||||
Net loss | (1,221,695) | (1,221,695) | |||||||||||||||||||||||||||||||||||||||
Net change in interest rate cash flow hedges, net of tax: $210 | 387 | 387 | |||||||||||||||||||||||||||||||||||||||
Other postretirement benefits liability adjustment, net of tax: $150 | 316 | 316 | |||||||||||||||||||||||||||||||||||||||
Dividends ($0.12 per share) | (30,655) | (30,655) | |||||||||||||||||||||||||||||||||||||||
Share-based compensation plans | 921 | 6,355 | 16,687 | 23,042 | |||||||||||||||||||||||||||||||||||||
Change in accounting principle | 496 | (496) | — | ||||||||||||||||||||||||||||||||||||||
Distribution of Equitrans Midstream Corporation (see Note 9) | (2,234) | 93,123 | 90,889 | ||||||||||||||||||||||||||||||||||||||
Other | (222) | (14,470) | (2,455) | (16,925) | |||||||||||||||||||||||||||||||||||||
Balance at December 31, 2019 | 255,171 | 7,818,205 | (32,507) | 2,023,089 | (5,199) | — | 9,803,588 | ||||||||||||||||||||||||||||||||||
Comprehensive loss, net of tax: | |||||||||||||||||||||||||||||||||||||||||
Net loss | (958,799) | (10) | (958,809) | ||||||||||||||||||||||||||||||||||||||
Other postretirement benefits liability adjustment, net of tax: $(36) | (156) | (156) | |||||||||||||||||||||||||||||||||||||||
Dividends ($0.03 per share) | (7,664) | (7,664) | |||||||||||||||||||||||||||||||||||||||
Share-based compensation plans | 174 | 18,911 | 3,159 | 22,070 | |||||||||||||||||||||||||||||||||||||
Capped Call Transactions (see Note 10) | (32,500) | (32,500) | |||||||||||||||||||||||||||||||||||||||
Issuance of common shares | 23,000 | 340,923 | 340,923 | ||||||||||||||||||||||||||||||||||||||
Contributions from noncontrolling interest | 7,500 | 7,500 | |||||||||||||||||||||||||||||||||||||||
Balance at December 31, 2020 | 278,345 | 8,145,539 | (29,348) | 1,056,626 | (5,355) | 7,490 | 9,174,952 | ||||||||||||||||||||||||||||||||||
Comprehensive loss (income), net of tax: | |||||||||||||||||||||||||||||||||||||||||
Net (loss) income | (1,142,747) | 1,246 | (1,141,501) | ||||||||||||||||||||||||||||||||||||||
Other postretirement benefits liability adjustment, net of tax: $254 | 744 | 744 | |||||||||||||||||||||||||||||||||||||||
Share-based compensation plans | 627 | 21,982 | 11,302 | 33,284 | |||||||||||||||||||||||||||||||||||||
Repurchase and retirement of common stock | (1,362) | (21,106) | (8,279) | (29,385) | |||||||||||||||||||||||||||||||||||||
Alta Acquisition (see Note 6) | 98,789 | 1,925,405 | 1,925,405 | ||||||||||||||||||||||||||||||||||||||
Contributions from noncontrolling interest | 7,500 | 7,500 | |||||||||||||||||||||||||||||||||||||||
Balance at December 31, 2021 | 376,399 | $ | 10,071,820 | $ | (18,046) | $ | (94,400) | $ | (4,611) | $ | 16,236 | $ | 9,970,999 |
Common shares authorized: 320,000 at December 31, 2019 and 640,000 at December 31, 2020 and 2021.
Preferred shares authorized: 3,000. There were no preferred shares issued or outstanding.
The accompanying notes are an integral part of these Consolidated Financial Statements.
24
EQT CORPORATION AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2021
1. Summary of Significant Accounting Policies
Principles of Consolidation. The Consolidated Financial Statements include the accounts of EQT Corporation and all subsidiaries, ventures and partnerships in which EQT holds a controlling interest (collectively, EQT or the Company). Intercompany accounts and transactions have been eliminated in consolidation. Management evaluates whether an entity or interest is a variable interest entity and whether the Company is the primary beneficiary; consolidation is required if both criteria are met. The Company records noncontrolling interest in its Consolidated Financial Statements for any non-wholly-owned consolidated subsidiary.
In 2020, the Company entered into a partnership with a third-party investor (the Partnership). Because the Partnership is a variable interest entity that the Company has the power to direct the activities that most significantly affect the Partnership's economic performance, the Company consolidates the Partnership.
Certain of the Company's midstream gathering systems are not wholly-owned but are operated by the Company pursuant to a construction, ownership and operation agreement. The Company records the pro rata share of revenues, expenses, assets and liabilities it is entitled under the agreement.
See "Investment in Equitrans Midstream" and "Equity Method Investments" for discussion of the Company's accounting of its investment in equity securities and equity method investments.
Segments. The Company's operations consist of one reportable segment. The Company has a single, company-wide management team that administers all properties as a whole rather than by discrete operating segments. The Company measures financial performance as a single enterprise and not on an area-by-area basis. Substantially all of the Company's operating revenues, income from operations and assets are generated and located in the United States.
Reclassification. Certain previously reported amounts have been reclassified to conform to the current year presentation.
Use of Estimates. The preparation of financial statements in conformity with United States generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the amounts reported herein. Actual results could differ from those estimates.
Cash and Cash Equivalents. The Company considers all highly-liquid investments with an original maturity of three months or less when purchased to be cash equivalents and accounts for such investments at cost. Interest earned on cash equivalents is included as a reduction of interest expense.
Accounts Receivable. The Company's accounts receivable relates primarily to the sales of natural gas, natural gas liquids (NGLs) and oil and amounts due from joint interest partners. See Note 2 for a discussion of amounts due from contracts with customers.
Derivative Instruments. See Note 3 for a discussion of the Company's derivative instruments and Note 4 for a description of the fair value hierarchy and a discussion of the Company's fair value measurements.
Prepaid Expenses and Other. The following table summarizes the Company's prepaid expenses and other current assets.
December 31, | |||||||||||
2021 | 2020 | ||||||||||
(Thousands) | |||||||||||
Margin requirements with counterparties (see Note 3) | $ | 147,773 | $ | 82,552 | |||||||
Prepaid expenses and other current assets | 43,662 | 21,063 | |||||||||
Total prepaid expenses and other | $ | 191,435 | $ | 103,615 |
25
Property, Plant and Equipment. The following table summarizes the Company's property, plant and equipment.
December 31, | |||||||||||
2021 | 2020 | ||||||||||
(Thousands) | |||||||||||
Oil and gas producing properties | $ | 25,523,854 | $ | 21,771,025 | |||||||
Less: Accumulated depreciation and depletion | 7,508,178 | 5,866,418 | |||||||||
Net oil and gas producing properties | 18,015,676 | 15,904,607 | |||||||||
Other properties, at cost less accumulated depreciation | 403,244 | 149,658 | |||||||||
Net property, plant and equipment | $ | 18,418,920 | $ | 16,054,265 |
The Company uses the successful efforts method of accounting for gas, NGLs and oil producing activities. Under this method, the cost of productive wells and related equipment, development dry holes and productive acreage, including productive mineral interests, are capitalized and depleted using the unit-of-production method. These costs include salaries, benefits and other internal costs directly attributable to production activities. The Company capitalized internal costs of approximately $58 million, $51 million and $77 million in 2021, 2020 and 2019, respectively. The Company also capitalized interest expense related to well development of approximately $18 million, $17 million and $24 million in 2021, 2020 and 2019, respectively. Depletion expense is calculated based on actual produced sales volume multiplied by the applicable depletion rate per unit. Depletion rates for leases and wells are each calculated by dividing net capitalized costs by the number of units expected to be produced over the life of the reserves separately. Costs for exploratory dry holes, exploratory geological and geophysical activities and delay rentals as well as other property carrying costs are charged to exploration expense. The Company's producing oil and gas properties had an overall average depletion rate of $0.89, $0.92 and $1.01 per Mcfe for the years ended December 31, 2021, 2020 and 2019, respectively.
There were no exploratory wells drilled during 2021, 2020 and 2019, and there were no capitalized exploratory well costs for the years ended December 31, 2021, 2020 and 2019.
Impairment of Long-lived Assets. The carrying values of the Company's 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 the Company's oil and gas properties has occurred, the Company compares 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 the Company 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.
There were no indicators of impairment identified in 2021 and 2020.
During the fourth quarter of 2019, there were indicators that the carrying values of certain of the Company's properties may be impaired due to depressed natural gas prices and changes in the Company's development strategy, including the Company's contemplation of a potential asset divestiture of certain of its non-strategic exploration and production assets. As a result of the 2019 impairment evaluation, the Company recorded total impairment of $1,124.4 million, of which $1,035.7 million was associated with the Company's non-strategic assets located in the Ohio Utica and $88.7 million was associated with the Company's Pennsylvania and West Virginia Utica assets. The impairment was recorded as a reduction to the assets' carrying values to their estimated fair values of approximately $839.4 million with respect to the Company's Ohio Utica assets and approximately $26.8 million with respect to the Company's Pennsylvania and West Virginia Utica assets. The fair value of the impaired assets, as determined at December 31, 2019, was based on significant inputs that are not observable in the market and, as such, are considered a Level 3 fair value measurement. See Note 4 for a description of the fair value hierarchy. Key assumptions included in the calculation of the fair value included the following: (i) reserves, including risk adjustments for probable reserves; (ii) future commodity prices; (iii) to the extent available, market-based indicators of fair value, including estimated proceeds that could be realized upon a potential disposition; (iv) production rates based on the Company's experience with similar properties; (v) future operating and development costs; (vi) inflation and (vii) a market-based weighted average cost of capital.
26
Impairment and Expiration of Leases. 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. The Company recognizes impairment if the Company does not have the intent to drill on the leased property prior to expiration of the lease or does not have the intent and ability to extend, renew, trade or sell the lease prior to expiration. The Company recognizes expense for lease expirations as the lease expires if the lease was not previously impaired. For the years ended December 31, 2021, 2020 and 2019, the Company recorded $311.8 million, $306.7 million and $556.4 million, respectively, for impairment and expiration of leases. The Company's unproved properties had a net book value of approximately $2,406 million and $2,292 million at December 31, 2021 and 2020, respectively.
Contract Asset. See Note 5 for discussion of the Company's contract asset.
The carrying value of the Company's contract asset is reviewed for impairment when events or circumstances indicate that the remaining carrying value may not be recoverable. To determine whether impairment of the Company's contract asset has occurred, the Company compares the estimated undiscounted future cash flows to the carrying value. Estimated future cash flows are based on estimated volume and the in-service date of the Mountain Valley Pipeline. If the contract asset's carrying amount exceeds the estimated future undiscounted cash flows, it is 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.
During 2020, the Company identified indicators that the carrying value of the contract asset may not be fully recoverable due to further delays of the timing of completion of the Mountain Valley Pipeline as well as changes to the regulatory landscape. The Company performed the first step of the impairment test and determined the estimated expected undiscounted future cash flows exceeded the carrying value of the contract asset, indicating the contract asset was not impaired. The estimated undiscounted future cash flows were based on significant inputs that are not observable in the market and, as such, are considered a Level 3 fair value measurement. See Note 4 for a description of the fair value hierarchy. Key assumptions in the calculation of estimated undiscounted future cash flows included estimated production volume subject to the Consolidated GGA (defined in Note 5) and a probability-weighted estimate of the in-service date of the Mountain Valley Pipeline. There were no additional indicators of impairment identified in 2021.
Investment in Equitrans Midstream Corporation. As of December 31, 2021, the Company owned approximately 23 million shares of common stock of Equitrans Midstream Corporation (Equitrans Midstream). The Company does not have the ability to exercise significant influence and does not have a controlling financial interest in Equitrans Midstream or any of its subsidiaries. As such, its investment in Equitrans Midstream is accounted for as an investment in equity securities and recorded at fair value in other assets in the Consolidated Balance Sheets. The fair value is calculated by multiplying the closing stock price of Equitrans Midstream's common stock by the number of shares of Equitrans Midstream's common stock owned by the Company. Changes in fair value are recorded in (income) loss on investments in the Statements of Consolidated Operations. See Note 4 for a description of the fair value hierarchy. Dividends received on the investment in Equitrans Midstream are recorded in dividend and other income in the Statements of Consolidated Operations. See Note 5.
Equity Method Investments. The Company applies the equity method of accounting to its investments over which it does not have the power to direct the activities that most significantly impact the investment's economic performance. The carrying value of the Company's equity method investments is recorded in other assets in the Consolidated Balance Sheets. The Company's pro-rata share of earnings in equity method investments is recorded in (income) loss from investments in the Statements of Consolidated Operations.
Intangible Assets. The Company's intangible assets, composed of non-compete agreements with former Rice Energy Inc. executives, were fully amortized as of December 31, 2020. In 2019 the Company recognized impairment of its intangible assets associated with non-compete agreements with former Rice Energy Inc. executives who are now employees of the Company.
27
Other Current Liabilities. The following table summarizes the Company's other current liabilities.
December 31, | |||||||||||
2021 | 2020 | ||||||||||
(Thousands) | |||||||||||
Accrued interest payable | $ | 88,614 | $ | 91,953 | |||||||
Accrued taxes other than income | 86,755 | 44,619 | |||||||||
Current portion of long-term capacity contracts | 57,440 | 50,504 | |||||||||
Accrued incentive compensation | 51,224 | 33,601 | |||||||||
Current portion of lease liabilities | 27,972 | 25,004 | |||||||||
Accrued severance | 3,815 | 2,536 | |||||||||
Income tax payable | — | 23,909 | |||||||||
Other accrued liabilities | 56,592 | 29,785 | |||||||||
Total other current liabilities | $ | 372,412 | $ | 301,911 |
Unamortized Debt Discount and Issuance Expense. Discounts and expenses incurred with the issuance of debt are amortized over the life of the debt. These amounts are presented as a reduction of senior notes in the Consolidated Balance Sheets. See Note 10.
Income Taxes. The Company files a consolidated U.S. federal income tax return and uses the asset and liability method to account for income taxes. The provision for income taxes represents amounts paid or estimated to be payable net of amounts refunded or estimated to be refunded for the current year and the change in deferred taxes exclusive of amounts recorded in other comprehensive loss. Any refinements to prior year taxes made in the current year due to new information are reflected as adjustments in the current period. Separate income taxes are calculated for items charged or credited directly to shareholders' equity.
Deferred tax assets and liabilities arise from temporary differences between the financial reporting and tax bases of the Company's assets and liabilities and are recognized using enacted tax rates for the effect of such temporary differences. Deferred tax assets are reduced by a valuation allowance if it is more likely than not that a portion or all of the deferred tax asset will not be realized. When evaluating whether or not a valuation allowance should be established, the Company exercises 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, the Company considers all available evidence, both positive and negative, including carrybacks, tax planning strategies, reversals of deferred tax assets and liabilities and forecasted future taxable income.
In accounting for uncertainty of a tax position taken or expected to be taken in a tax return, the Company uses a recognition threshold and measurement attribute for the financial statement recognition and measurement. The recognition threshold requires the Company to determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. If it is more likely than not that a tax position will be sustained, the Company measures and recognizes the tax position at the largest amount of benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. To determine the amount of financial statement benefit recorded for uncertain tax positions, the Company considers 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. The Company recognizes accrued interest and penalties related to unrecognized tax benefits in income tax expense. See Note 9.
Insurance. The Company maintains insurance to cover traditional insurable risks such as general liability, workers compensation, auto liability, environmental liability, property damage, business interruption, fiduciary liability, director and officers' liability and other risks. These policies may be subject to deductible or retention amounts, coverage limitations and exclusions. The Company was previously self-insured for certain material losses related to general liability and certain other casualty coverages, such as workers compensation, auto liability and environmental liability. However, the Company is no longer self-insured with respect to any material losses related to general liability, workers compensation or environmental liability arising on or after November 12, 2020, or for losses related to auto liability arising on or after November 12, 2019. Reserves are estimated based on analyses of historical data and actuarial estimates, where applicable, and are not discounted. The recorded reserves represent estimates of the ultimate cost of claims incurred as of the balance sheet date. The liabilities are reviewed by the Company quarterly and by independent actuaries, where applicable, annually to ensure appropriateness.
28
Asset Retirement Obligations. The Company accrues 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 the Company's plugging and abandonment obligations is recorded at the time the obligation is incurred, which is typically at the time the well is spud. Upon initial recognition of an asset retirement obligation, the Company increases the carrying amount of the long-lived asset by the same amount as the liability. Over time, the liabilities are accreted for the change in their present value through charges to depreciation and depletion expense. The initial capitalized costs are depleted over the useful lives of the related assets.
The Company's asset retirement obligations related to the abandonment of oil and gas producing facilities include reclaiming drilling sites, plugging wells and dismantling related structures. Estimates are based on historical experience of plugging and abandoning wells and reclaiming or disposing other assets and estimated remaining lives of the wells and assets.
The following table presents a reconciliation of the beginning and ending carrying amounts of the Company's asset retirement obligations included in other liabilities and credits in the Consolidated Balance Sheets.
December 31, | |||||||||||
2021 | 2020 | ||||||||||
(Thousands) | |||||||||||
Balance at January 1 | $ | 523,557 | $ | 461,821 | |||||||
Accretion expense | 30,690 | 22,506 | |||||||||
Liabilities incurred | 10,738 | 10,293 | |||||||||
Liabilities settled | (19,149) | (4,030) | |||||||||
Liabilities assumed in acquisitions | 113,590 | 45,825 | |||||||||
Liabilities removed in divestitures | (3,315) | (54,836) | |||||||||
Change in estimates (a) | 5,223 | 41,978 | |||||||||
Balance at December 31 | $ | 661,334 | $ | 523,557 |
(a)During 2020, the Company had changes in estimates for the plugging of horizontal and conventional wells that were related primarily to pad reclamation and increased cost assumptions for the Company's compliance with existing regulatory requirements that were derived, in part, from recent plugging experience and actual costs incurred.
The Company does not have any assets that are legally restricted for purposes of settling these obligations. The Company operates in several states that have implemented expanded requirements that resulted in the Company's use of additional materials during the plugging process, which has increased the estimated cost for plugging horizontal and conventional wells.
Revenue Recognition. For information on revenue recognition from contracts with customers and gains and losses on derivative commodity instruments see Notes 2 and 3, respectively.
Transportation and Processing. Costs incurred to gather, process and transport gas produced by the Company to market sales points are recorded as transportation and processing costs in the Statements of Consolidated Operations. The Company markets some transportation for resale. These costs, which are not incurred to transport gas produced by the Company, are reflected as a deduction from net marketing services and other revenues.
Share-based Compensation. See Note 13 for a discussion of the Company's share-based compensation plans.
Provision for Doubtful Accounts. Reserves for uncollectible accounts are recorded in selling, general and administrative expense in the Statements of Consolidated Operations. Judgment is required to assess the ultimate realization of the Company's accounts receivable. Reserves are based on historical experience, current and expected economic trends and specific information about customer accounts, such as the customer's creditworthiness.
29
Other Operating Expenses. The following table summarizes the Company's other operating expenses.
Years Ended December 31, | |||||||||||||||||
2021 | 2020 | 2019 | |||||||||||||||
(Thousands) | |||||||||||||||||
Transactions | $ | 57,430 | $ | 11,739 | $ | — | |||||||||||
Reorganization, including severance and contract terminations | 7,458 | 5,448 | 97,702 | ||||||||||||||
Changes in legal reserves, including settlements | 5,175 | 11,350 | 82,395 | ||||||||||||||
Proxy | — | — | 19,343 | ||||||||||||||
Total other operating expenses | $ | 70,063 | $ | 28,537 | $ | 199,440 |
Other Postretirement Benefits Plan. The Company sponsors a postretirement benefits plan. The Company recognized expense related to its defined contribution plan of $7.0 million, $6.5 million and $8.9 million for the years ended December 31, 2021, 2020 and 2019, respectively.
Earnings Per Share (EPS). Basic EPS is computed by dividing net income attributable to EQT Corporation by the weighted average number of common shares outstanding during the period. Diluted EPS is computed by dividing net income attributable to EQT Corporation by the weighted average number of common shares and potentially dilutive securities, net of shares assumed to be repurchased using the treasury stock method. Potentially dilutive securities arise from the assumed conversion of outstanding stock options and other share-based awards as well as the Convertible Notes (defined in Note 10). Purchases of treasury shares are calculated using the average share price of EQT common stock during the period.
In periods when the Company reports a net loss, all options, restricted stock, performance awards and stock appreciation rights are excluded from the calculation of diluted weighted average shares outstanding because of their anti-dilutive effect on loss per share. As a result, for the years ended December 31, 2021, 2020 and 2019, all such securities, totaling 8,237,352, 6,778,383 and 3,035,247, respectively, were excluded from potentially dilutive securities because of their anti-dilutive effect on loss per share.
As further discussed in Note 10, the Company issued the Convertible Notes during the second quarter of 2020. The Company applies the if-converted method to calculate the impact of the Convertible Notes on diluted EPS, as the assumption of cash settlement of the notes is not available for the purpose of calculating EPS. For the years ended December 31, 2021 and 2020, approximately 33.3 million shares were excluded from potentially dilutive securities because of its anti-dilutive effect on loss per share.
Supplemental Cash Flow Information. The following table summarizes net cash paid (received) for interest and income taxes and non-cash activity included in the Statements of Consolidated Cash Flows.
Years Ended December 31, | |||||||||||||||||
2021 | 2020 | 2019 | |||||||||||||||
(Thousands) | |||||||||||||||||
Cash paid (received) during the year for: | |||||||||||||||||
Interest, net of amount capitalized | $ | 280,511 | $ | 195,681 | $ | 198,562 | |||||||||||
Income taxes, net | 19,155 | (448,906) | (1,710) | ||||||||||||||
Non-cash activity during the period for: | |||||||||||||||||
Increase in right-of-use assets and lease liabilities, net | 20,834 | 18,877 | 113,350 | ||||||||||||||
Increase in asset retirement costs and obligations | 15,961 | 52,271 | 169,387 | ||||||||||||||
Capitalization of non-cash equity share-based compensation | 4,994 | 3,142 | — | ||||||||||||||
Equity issued as consideration for the Alta Acquisition (see Note 6) | 1,925,405 | — | — |
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Recently Issued Accounting Standards
In December 2019, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2019-12, Income Taxes: Simplifying the Accounting for Income Taxes. This ASU simplifies accounting for income taxes by eliminating certain exceptions to Accounting Standards Codification (ASC) 740, Income Taxes, related to the general approach for intraperiod tax allocation, methodology for calculating income taxes in an interim period and recognition of deferred taxes when there are investment ownership changes. In addition, this ASU simplifies aspects of accounting for franchise taxes and interim period effects of enacted changes in tax laws or rates and provides clarification on accounting for transactions that result in a step up in the tax basis of goodwill and allocation of consolidated income tax expense to separate financial statements of entities not subject to income tax. The Company adopted this ASU in the first quarter of 2021 with no material changes to its financial statements or disclosures.
In August 2020, the FASB issued ASU 2020-06, Debt with Conversion and Other Options and Derivatives and Hedging: Accounting for Convertible Instruments and Contracts in an Entity's Own Equity. This ASU simplifies accounting for convertible instruments by removing certain separation models for convertible instruments. For convertible instruments with conversion features that are not accounted for as derivatives under ASC 815 or do not result in substantial premiums accounted for as paid-in capital, the convertible instrument's embedded conversion features are no longer separated from the host contract. Consequently, and as long as no other feature requires bifurcation and recognition as a derivative, the convertible instrument is accounted for as a single liability measured at its amortized cost. This ASU also requires the application of the if-converted method to calculate the impact of convertible instruments on diluted earnings per share, which results in increased dilutive securities as the assumption of cash settlement of the notes is not available for the purpose of calculating earnings per share. This ASU also adds several new disclosure requirements.
The Company adopted this ASU effective as of January 1, 2022 using the full retrospective method of adoption. Accordingly, Notes 9 and 10 to these consolidated financial statements have been recast. See Note 10 for disclosures of the changes to the consolidated financial statements.
Subsequent Events. The Company has evaluated subsequent events through the original date of the financial statement issuance, which was February 10, 2022.
2. Revenue from Contracts with Customers
Under the Company's natural gas, NGLs and oil sales contracts, the Company generally considers the delivery of each unit (MMBtu or Bbl) to be a separate performance obligation that is satisfied upon delivery. These contracts typically require payment within 25 days of the end of the calendar month in which the commodity is delivered. A significant number of these contracts contain variable consideration because the payment terms refer to market prices at future delivery dates. In these situations, the Company has not identified a standalone selling price because the terms of the variable payments relate specifically to the Company's efforts to satisfy the performance obligations. Other contracts, such as fixed price contracts or contracts with a fixed differential to New York Mercantile Exchange (NYMEX) or index prices, contain fixed consideration. The fixed consideration is allocated to each performance obligation on a relative standalone selling price basis, which requires judgment from management. For these contracts, the Company generally concludes that the fixed price or fixed differentials in the contracts are representative of the standalone selling price.
Based on management's judgment, the performance obligations for the sale of natural gas, NGLs and oil are satisfied at a point in time because the customer obtains control and legal title of the asset when the natural gas, NGLs or oil is delivered to the designated sales point.
The sales of natural gas, NGLs and oil presented in the Statements of Consolidated Operations represent the Company's share of revenues net of royalties and exclude revenue interests owned by others. When selling natural gas, NGLs and oil on behalf of royalty or working interest owners, the Company acts as an agent and, thus, reports the revenue on a net basis.
For contracts with customers where the Company's performance obligations had been satisfied and an unconditional right to consideration existed as of the balance sheet date, the Company recorded amounts due from contracts with customers of $1,093.9 million and $394.1 million in accounts receivable in the Consolidated Balance Sheets as of December 31, 2021 and 2020, respectively.
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The table below provides disaggregated information on the Company's revenues. Certain other revenue contracts are outside the scope of ASU 2014-09, Revenue from Contracts with Customers. These contracts are reported in net marketing services and other in the Statements of Consolidated Operations. Derivative contracts are also outside the scope of ASU 2014-09.
Years Ended December 31, | |||||||||||||||||
2021 | 2020 | 2019 | |||||||||||||||
(Thousands) | |||||||||||||||||
Revenues from contracts with customers: | |||||||||||||||||
Natural gas sales | $ | 6,180,176 | $ | 2,459,854 | $ | 3,559,809 | |||||||||||
NGLs sales | 531,510 | 169,871 | 197,985 | ||||||||||||||
Oil sales | 92,334 | 20,574 | 33,620 | ||||||||||||||
Total revenues from contracts with customers | $ | 6,804,020 | $ | 2,650,299 | $ | 3,791,414 | |||||||||||
Other sources of revenue: | |||||||||||||||||
(Loss) gain on derivatives not designated as hedges | (3,775,042) | 400,214 | 616,634 | ||||||||||||||
Net marketing services and other | 35,685 | 8,330 | 8,436 | ||||||||||||||
Total operating revenues | $ | 3,064,663 | $ | 3,058,843 | $ | 4,416,484 |
The following table summarizes the transaction price allocated to the Company's remaining performance obligations on all contracts with fixed consideration as of December 31, 2021. Amounts shown exclude contracts that qualified for the exception to the relative standalone selling price method as of December 31, 2021.
2022 | 2023 | Total | |||||||||||||||||||||||||||
(Thousands) | |||||||||||||||||||||||||||||
Natural gas sales | $ | 14,970 | $ | 6,794 | $ | 21,764 |
3. Derivative Instruments
The Company's primary market risk exposure is the volatility of future prices for natural gas and NGLs, which can affect the Company's operating results. The Company uses derivative commodity instruments to hedge its cash flows from sales of produced natural gas and NGLs. The overall objective of the Company's hedging program is to protect cash flows from undue exposure to the risk of changing commodity prices.
The derivative commodity instruments used by the Company are primarily swap, collar and option agreements. These agreements may require payments to, or receipt of payments from, counterparties based on the differential between two prices for the commodity. The Company uses these agreements to hedge its NYMEX and basis exposure. The Company may also use other contractual agreements when executing its commodity hedging strategy. The Company typically enters into over the counter (OTC) derivative commodity instruments with financial institutions, and the creditworthiness of all counterparties is regularly monitored.
The Company does not designate any of its derivative instruments as cash flow hedges; therefore, all changes in fair value of the Company's derivative instruments are recognized in operating revenues in the Statements of Consolidated Operations. The Company recognizes all derivative instruments as either assets or liabilities at fair value on a gross basis. These derivative instruments are reported as either current assets or current liabilities due to their highly liquid nature. The Company can net settle its derivative instruments at any time.
Contracts that result in physical delivery of a commodity expected to be sold by the Company in the normal course of business are generally designated as normal sales and are exempt from derivative accounting. Contracts that result in the physical receipt or delivery of a commodity but are not designated or do not meet all of the criteria to qualify for the normal purchase and normal sale scope exception are subject to derivative accounting.
The Company's OTC derivative instruments generally require settlement in cash. The Company also enters into exchange traded derivative commodity instruments that are generally settled with offsetting positions. Settlements of derivative commodity instruments are reported as a component of cash flows from operating activities in the Statements of Consolidated Cash Flows.
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With respect to the derivative commodity instruments held by the Company, the Company hedged portions of its expected sales of production and portions of its basis exposure covering approximately 2,184 billion cubic feet (Bcf) of natural gas and 3,055 thousand barrels (Mbbl) of NGLs as of December 31, 2021 and 1,955 Bcf of natural gas and 3,462 Mbbl of NGLs as of December 31, 2020. The open positions at December 31, 2021 and 2020 had maturities extending through December 2027 and December 2024, respectively.
Certain of the Company's OTC derivative instrument contracts provide that, if the Company's credit rating assigned by Moody's Investors Service, Inc. (Moody's), S&P Global Ratings (S&P) or Fitch Ratings Service (Fitch) is below the agreed-upon credit rating threshold (typically, below investment grade), and if the associated derivative liability exceeds the agreed-upon dollar threshold for such credit rating, the counterparty to such contract can require the Company to deposit collateral. Similarly, if such counterparty's credit rating assigned by Moody's, S&P or Fitch is below the agreed-upon credit rating threshold, and if the associated derivative liability exceeds the agreed-upon dollar threshold for such credit rating, the Company can require the counterparty to deposit collateral with the Company. Such collateral can be up to 100% of the derivative liability. Investment grade refers to the quality of a company's credit as assessed by one or more credit rating agencies. To be considered investment grade, a company must be rated "Baa3" or higher by Moody's, "BBB–" or higher by S&P and "BBB–" or higher by Fitch. Anything below these ratings is considered non-investment grade. As of December 31, 2021, the Company's senior notes were rated "Ba1" by Moody's, "BB+" by S&P and "BB+" by Fitch.
When the net fair value of any of the Company's OTC derivative instrument contracts represents a liability to the Company that is in excess of the agreed-upon dollar threshold for the Company's then-applicable credit rating, the counterparty has the right to require the Company to remit funds as a margin deposit in an amount equal to the portion of the derivative liability that is in excess of the dollar threshold amount. The Company records these deposits as a current asset in the Consolidated Balance Sheets. As of December 31, 2021 and 2020, the aggregate fair value of all OTC derivative instruments with credit rating risk-related contingent features that were in a net liability position was $594.9 million and $137.7 million, respectively, for which, the Company deposited and recorded current assets of $0.1 million and $21.1 million, respectively.
When the net fair value of any of the Company's OTC derivative instrument contracts represents an asset to the Company that is in excess of the agreed-upon dollar threshold for the counterparty's then-applicable credit rating, the Company has the right to require the counterparty to remit funds as a margin deposit in an amount equal to the portion of the derivative asset that is in excess of the dollar threshold amount. The Company records these deposits as a current liability in the Consolidated Balance Sheets. As of both December 31, 2021 and 2020, there were no such deposits recorded in the Consolidated Balance Sheets.
When the Company enters into exchange traded natural gas contracts, exchanges may require the Company to remit funds to the corresponding broker as good faith deposits to guard against the risks associated with changing market conditions. The Company is required to make such deposits based on an established initial margin requirement and the net liability position, if any, of the fair value of the associated contracts. The Company records these deposits as a current asset in the Consolidated Balance Sheets. When the fair value of such contracts is in a net asset position, the broker may remit funds to the Company. The Company records these deposits as a current liability in the Consolidated Balance Sheets. The initial margin requirements are established by the exchanges based on the price, volatility and the time to expiration of the contract. The margin requirements are subject to change at the exchanges' discretion. As of December 31, 2021 and 2020, the Company recorded $147.7 million and $61.5 million, respectively, of such deposits as current assets in the Consolidated Balance Sheets.
Refer to Note 5 for a discussion of the derivative liability recorded in connection with the Equitrans Share Exchange (defined therein).
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The Company has netting agreements with financial institutions and its brokers that permit net settlement of gross commodity derivative assets against gross commodity derivative liabilities. The table below summarizes the impact of netting agreements and margin deposits on gross derivative assets and liabilities.
Gross derivative instruments recorded in the Consolidated Balance Sheet | Derivative instruments subject to master netting agreements | Margin requirements with counterparties | Net derivative instruments | ||||||||||||||||||||
December 31, 2021 | (Thousands) | ||||||||||||||||||||||
Asset derivative instruments at fair value | $ | 543,337 | $ | (468,266) | $ | — | $ | 75,071 | |||||||||||||||
Liability derivative instruments at fair value | 2,413,608 | (468,266) | (147,773) | 1,797,569 | |||||||||||||||||||
December 31, 2020 | |||||||||||||||||||||||
Asset derivative instruments at fair value | $ | 527,073 | $ | (328,809) | $ | — | $ | 198,264 | |||||||||||||||
Liability derivative instruments at fair value | 600,877 | (328,809) | (82,552) | 189,516 |
4. Fair Value Measurements
The Company records its financial instruments, which are principally derivative instruments, at fair value in the Consolidated Balance Sheets. The Company estimates the fair value of its 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 the Company's credit standing on the fair value of liabilities and the effect of the counterparty's credit standing on the fair value of assets. The Company estimates nonperformance risk by analyzing publicly available market information, including a comparison of the yield on debt instruments with credit ratings similar to the Company's or counterparty's credit rating and the yield on a risk-free instrument.
The Company has categorized its assets and liabilities recorded at fair value into a three-level fair value hierarchy based on the priority of the inputs to the valuation technique. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets and liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Assets and liabilities that use Level 2 inputs primarily include the Company's swap, collar and option agreements.
Exchange traded commodity swaps have Level 1 inputs. The fair value of the commodity swaps with Level 2 inputs is based on standard industry income approach models that use significant observable inputs, including, but not limited to, NYMEX natural gas forward curves, LIBOR-based discount rates, basis forward curves and NGLs forward curves. The Company's collars and options are valued using standard industry income approach option models. The significant observable inputs used by the option pricing models include NYMEX forward curves, natural gas volatilities and LIBOR-based discount rates.
The table below summarizes assets and liabilities measured at fair value on a recurring basis.
Fair value measurements at reporting date using: | |||||||||||||||||||||||
Gross derivative instruments recorded in the Consolidated Balance Sheets | Quoted prices in active markets for identical assets (Level 1) | Significant other observable inputs (Level 2) | Significant unobservable inputs (Level 3) | ||||||||||||||||||||
December 31, 2021 | (Thousands) | ||||||||||||||||||||||
Asset derivative instruments at fair value | $ | 543,337 | $ | 66,833 | $ | 476,504 | $ | — | |||||||||||||||
Liability derivative instruments at fair value | 2,413,608 | 126,053 | 2,287,555 | — | |||||||||||||||||||
December 31, 2020 | |||||||||||||||||||||||
Asset derivative instruments at fair value | $ | 527,073 | $ | 70,603 | $ | 456,470 | $ | — | |||||||||||||||
Liability derivative instruments at fair value | 600,877 | 93,361 | 507,516 | — |
The carrying values of cash equivalents, accounts receivable and accounts payable approximate fair value due to their short-term maturities. The carrying value of the Company's investment in Equitrans Midstream approximates fair value as Equitrans
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Midstream is a publicly traded company. The carrying value of borrowings under the Company's credit facility approximates fair value as the interest rate is based on prevailing market rates. The Company considered all of these fair values to be Level 1 fair value measurements.
The Company estimates the fair value of its senior notes using established fair value methodology. Because not all of the Company's senior notes are actively traded, their fair value is a Level 2 fair value measurement. As of December 31, 2021 and 2020, the Company's senior notes had a fair value of approximately $6.5 billion and $5.2 billion, respectively, and a carrying value of approximately $5.5 billion and $4.6 billion, respectively, inclusive of any current portion. The fair value of the Company's note payable to EQM Midstream Partners, LP (EQM) is estimated using an income approach model with a market-based discount rate and is a Level 3 fair value measurement. As of December 31, 2021 and 2020, the Company's note payable to EQM had a fair value of approximately $118 million and $130 million, respectively, and a carrying value of approximately $100 million and $105 million, respectively, inclusive of any current portion. See Note 10 for further discussion of the Company's debt.
The Company recognizes transfers between Levels as of the actual date of the event or change in circumstances that caused the transfer. There were no transfers between Levels 1, 2 and 3 during the periods presented.
See Note 5 for a discussion of the fair value measurement of the Equitrans Share Exchange (defined therein). See Notes 6, 7 and 8 for a discussion of the fair value measurement of the Company's acquisitions, asset exchange transactions and divestiture, respectively. See Note 1 for a discussion of the fair value measurement and any subsequent impairments of the Company's proved and unproved oil and gas properties and other long-lived assets.
5. Equitrans Share Exchange
During the first quarter of 2020, the Company sold to Equitrans Midstream a total of 25,299,752 shares of Equitrans Midstream's common stock in exchange for approximately $52 million in cash and rate relief under certain of the Company's gathering contracts with EQM, an affiliate of Equitrans Midstream (the Equitrans Share Exchange). The rate relief was effected through the execution of a consolidated gas gathering and compression agreement entered into between the Company and an affiliate of EQM (the Consolidated GGA). The Company recorded in the Consolidated Balance Sheet a contract asset representing the estimated fair value of the rate relief and, beginning on the Mountain Valley Pipeline in-service date, expects to recognize amortization of the contract asset over a period of approximately four years in a manner consistent with the expected timing of the Company's realization of the economic benefits of the rate relief.
The Consolidated GGA provides for additional cash bonus payments (the Henry Hub Cash Bonus) payable by the Company to EQM during the period beginning on the first day of the quarter in which the Mountain Valley Pipeline is placed in service and ending on the earlier of 36 months thereafter or December 31, 2024. Such payments are conditioned upon the quarterly average of the NYMEX Henry Hub natural gas settlement price exceeding certain price thresholds. As of December 31, 2021 and 2020, the derivative liability related to the Henry Hub Cash Bonus was approximately $111 million and $107 million, respectively. In addition, the Consolidated GGA provides a cash payment option that grants the Company the right to receive payments from EQM, in lieu of receiving the rate relief under the Consolidated GGA, beginning January 1, 2022 and ending on the earlier of the Mountain Valley Pipeline in-service date or December 31, 2022.
The fair value of the contract asset was based on significant inputs that are not observable in the market and, as such, is a Level 3 fair value measurement. 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. The fair value of the derivative liability related to the Henry Hub Cash Bonus was based on significant inputs that were interpolated from observable market data and, as such, is a Level 2 fair value measurement. See Note 4 for a description of the fair value hierarchy.
6. Acquisitions
Reliance Asset Acquisition.
On April 1, 2021, the Company closed on the acquisition of certain oil and gas assets (the Reliance Asset Acquisition) from Reliance Marcellus, LLC (Reliance), pursuant to the Company's exercise of a preferential purchase right that was triggered by Northern Oil and Gas, Inc.'s acquisition of Reliance's Marcellus assets. The total purchase price for the acquisition was approximately $69 million, and the assets acquired consisted of approximately 40 MMcfe per day of current production and 4,100 net acres located in southwest Pennsylvania. The Reliance Asset Acquisition was accounted for as an asset acquisition and, as such, its proceeds were allocated to property, plant and equipment.
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Alta Acquisition.
On July 21, 2021, the Company completed its acquisition (the Alta Acquisition) of Alta Marcellus Development, LLC and ARD Operating, LLC and subsidiaries (together, the Alta Target Entities), pursuant to that certain Membership Interest Purchase Agreement, dated May 5, 2021 (the Alta Purchase Agreement), by and among the Company, EQT Acquisition HoldCo LLC (a wholly-owned indirect subsidiary of the Company), Alta Resources Development, LLC (Alta Resources) and the Alta Target Entities. The Alta Target Entities collectively held all of Alta Resources' upstream and midstream assets and liabilities. The purchase price for the Alta Acquisition consisted of approximately $1.0 billion in cash and 98,789,388 shares of EQT common stock, as adjusted pursuant to customary closing purchase price adjustments set forth in the Alta Purchase Agreement. The Alta Purchase Agreement has an effective date of January 1, 2021.
As a result of the Alta Acquisition, the Company acquired approximately 300,000 net Northeast Marcellus acres, approximately 1.0 Bcfe per day of current net production, approximately 300 miles of midstream gathering systems, approximately 100 miles of a freshwater system and a firm transportation portfolio to premium demand markets.
Allocation of Purchase Price. The Alta Acquisition was accounted for as a business combination using the acquisition method. The table below summarizes the preliminary purchase price and estimated fair values of assets acquired and liabilities assumed as of July 21, 2021. Certain information necessary to complete the purchase price allocation is not yet available, including, but not limited to, final appraisals of assets acquired and liabilities assumed. The Company expects to complete the purchase price allocation once it has received all necessary information, at which time the value of the assets acquired and liabilities assumed will be revised, if necessary.
Preliminary Purchase Price Allocation | ||||||||
(Thousands) | ||||||||
Consideration: | ||||||||
Equity | $ | 1,925,405 | ||||||
Cash | 1,000,000 | |||||||
Total consideration | $ | 2,925,405 | ||||||
Fair value of assets acquired: | ||||||||
Cash and cash equivalents | $ | 43,199 | ||||||
Accounts receivable, net | 159,539 | |||||||
Property, plant and equipment | 3,143,767 | |||||||
Other assets | 6,309 | |||||||
Amount attributable to assets acquired | $ | 3,352,814 | ||||||
Fair value of liabilities assumed: | ||||||||
Accounts payable | $ | 131,214 | ||||||
Derivative instruments, at fair value | 169,744 | |||||||
Other current liabilities | 7,851 | |||||||
Other liabilities and credits | 118,600 | |||||||
Amount attributable to liabilities assumed | $ | 427,409 |
The fair value of the acquired natural gas and oil properties was measured using discounted cash flow valuation techniques based on inputs that are not observable in the market and, as such, are considered Level 3 fair value measurements. Significant inputs include 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. The fair value of the acquired undeveloped properties was primarily measured using discounted cash flow valuation techniques based on inputs that are not observable in the market and, as such, are considered Level 3 fair value measurements. Significant inputs include timing and amount of future development from a market participant perspective.
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The fair value of the acquired midstream gathering systems was measured primarily using the cost approach based on inputs that are not observable in the market and, as such, are considered Level 3 fair value measurements. Significant inputs include replacement costs for similar assets, relative age of the acquired assets and any potential economic or functional obsolescence associated with the acquired assets.
See Note 4 for a description of the fair value hierarchy.
Post-Acquisition Operating Results. The Alta Target Entities contributed the following to the Company's consolidated results.
July 21, 2021 through December 31, 2021 | ||||||||
(Thousands) | ||||||||
Sales of natural gas, NGLs and oil | $ | 725,807 | ||||||
Loss on derivatives not designated as hedges | (168,017) | |||||||
Net marketing services and other | 7,284 | |||||||
Total operating revenues | $ | 565,074 | ||||||
Net income | $ | 233,254 |
Unaudited Pro Forma Information. The table below summarizes the Company's results as though the Alta Acquisition had been completed on January 1, 2020. Certain of Alta Resources' historical amounts were reclassified to conform to the Company's financial presentation of operations. The following unaudited pro forma information is provided for informational purposes only and does not represent what consolidated results of operations would have been had the Alta Acquisition occurred on January 1, 2020 nor are they necessarily indicative of future consolidated results of operations.
Years Ended December 31, | |||||||||||
2021 | 2020 | ||||||||||
(Thousands, except per share amounts) | |||||||||||
Pro forma sales of natural gas, NGLs and oil | $ | 7,248,870 | $ | 3,092,762 | |||||||
Pro forma (loss) gain on derivatives not designated as hedges | (3,902,076) | 501,910 | |||||||||
Pro forma net marketing services and other | 40,491 | 17,737 | |||||||||
Pro forma total operating revenues | $ | 3,387,285 | $ | 3,612,409 | |||||||
Pro forma net loss | $ | (1,132,181) | $ | (957,377) | |||||||
Pro forma net income (loss) attributable to noncontrolling interest | 1,246 | (10) | |||||||||
Pro forma net loss attributable to EQT Corporation | $ | (1,133,427) | $ | (957,367) | |||||||
Pro forma loss per share (basic) | $ | (3.51) | $ | (3.67) | |||||||
Pro forma loss per share (diluted) | $ | (3.51) | $ | (3.67) |
Chevron Acquisition.
In the fourth quarter of 2020, the Company acquired upstream assets and an investment in midstream gathering assets located in the Appalachian Basin from Chevron U.S.A. Inc. (Chevron) for an aggregate purchase price of $735 million, subject to certain purchase price adjustments (the Chevron Acquisition). The transaction closed on November 30, 2020 and had an effective date of July 1, 2020.
The Chevron Acquisition included approximately 335,000 net Marcellus acres, approximately 400,000 net Utica acres, approximately 550 gross wells, which are producing approximately 450 net MMcfe per day, and approximately 100 work-in-process wells at various stages in the development cycle. The Chevron Acquisition also included a 31% investment in Laurel Mountain Midstream, LLC (LMM), which owns gathering assets that are operated by The Williams Companies, Inc., and two water systems that provide both fresh and produced water handling capabilities.
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The Company does not have the power to direct the activities that most significantly impact LMM's economic performance; therefore, the Company is not the primary beneficiary and accounts for its investment in LMM as an equity method investment. The Company's pro-rata share of earnings in LMM is recorded in (income) loss from investments on the Statements of Consolidated Operations.
Allocation of Purchase Price. The Chevron Acquisition was accounted for as a business combination using the acquisition method. The following table summarizes the purchase price and the fair values of assets acquired and liabilities assumed as of November 30, 2020. The Company completed the purchase price allocation during the fourth quarter of 2021, at which time the value of the assets acquired and liabilities assumed were revised. The purchase accounting adjustments recorded in 2021 were not material.
Purchase Price Allocation | ||||||||
(Thousands) | ||||||||
Consideration: | ||||||||
Cash (a) | $ | 701,985 | ||||||
Settlement of pre-existing relationships | 6,645 | |||||||
Total consideration | $ | 708,630 | ||||||
Fair value of assets acquired: | ||||||||
Prepaid expenses and other | $ | 10,583 | ||||||
Net property, plant and equipment | 725,319 | |||||||
Other assets | 97,247 | |||||||
Amount attributable to assets acquired | $ | 833,149 | ||||||
Fair value of liabilities assumed: | ||||||||
Accounts payable | $ | 3,347 | ||||||
Other current liabilities | 18,410 | |||||||
Deferred income taxes | 951 | |||||||
Other liabilities and credits (b) | 101,811 | |||||||
Amount attributable to liabilities assumed | $ | 124,519 |
(a)The difference between cash consideration and the aggregate purchase price of $735 million represents the results of operating activities between the effective date of July 1, 2020 and the closing date of November 30, 2020 as well as amounts related to customary post-closing matters.
(b)Other liabilities and credits included liabilities due to minimum volume commitment (MVC) contracts as well as liabilities for asset retirement obligations and environmental obligations.
The fair value of the acquired natural gas and oil properties was measured using discounted cash flow valuation techniques based on inputs that are not observable in the market and, as such, are considered Level 3 fair value measurements. Significant inputs include 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. The fair value of the undeveloped properties was measured using the guideline transaction method based on inputs that are not observable in the market and, as such, are considered Level 3 fair value measurements. Significant inputs include future development plans from a market participant perspective and value per undeveloped acre.
The fair value of the acquired investment in LMM, which is included in other assets on the Consolidated Balance Sheet, was primarily measured using discounted cash flow valuation techniques. A majority of the inputs are not observable in the market and, as such, are considered Level 3 fair value measurements. Significant inputs include projected revenues, expenses and capital expenditures.
The fair value of the acquired MVC liabilities was measured using expected throughput and annual MVCs per associated contract calculated on a discounted basis. A majority of the inputs are not observable in the market and, as such, are considered Level 3 fair value measurements. Significant inputs include estimated future volume and market participant cost of debt.
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7. Asset Exchange Transactions
2020 Asset Exchange Transactions. During 2020, the Company closed on various acreage trade agreements (collectively, the 2020 Asset Exchange Transactions), pursuant to which the Company exchanged approximately 24,400 aggregate net revenue interest acres across Greene, Allegheny, Armstrong, Westmoreland and Washington Counties, Pennsylvania; Wetzel and Marshall Counties, West Virginia; and Belmont County, Ohio for approximately 19,400 aggregate net revenue interest acres across Greene and Washington Counties, Pennsylvania; Marshall, Wetzel and Marion Counties, West Virginia; and Belmont County, Ohio. As a result of the 2020 Asset Exchange Transactions, the Company recognized a net loss of $61.6 million in (gain) loss/impairment on sale/exchange of long-lived assets in the Statement of Consolidated Operations for the year ended December 31, 2020.
2019 Asset Exchange Transaction. During the third quarter of 2019, the Company closed on an acreage trade agreement and purchase and sale agreement with a third party (the 2019 Asset Exchange Transaction), pursuant to which the Company exchanged approximately 16,000 net revenue interest acres primarily in Wetzel and Marion Counties, West Virginia. Under the terms of the purchase and sale agreement, the Company assigned to the third party a gas gathering agreement that covers a portion of Tyler County, West Virginia and provides a firm gathering commitment, and the Company was released from its remaining obligations under that gas gathering agreement. As consideration for the third party's assumption of the Tyler County gas gathering agreement, the Company agreed to reimburse the third party for certain firm gathering costs under the gas gathering agreement through December 2022 and assign the third party an additional approximately 3,000 net revenue interest acres in Tyler and Wetzel Counties, West Virginia.
As a result of the 2019 Asset Exchange Transaction, the Company recognized a net loss of $13.9 million in (gain) loss/impairment on sale/exchange of long-lived assets in the Statement of Consolidated Operations for the year ended December 31, 2019. As of December 31, 2021 and 2020, the liability for the reimbursement of those certain firm gathering costs was $12.6 million and $25.8 million, respectively, and was recorded in other current and noncurrent liabilities in the Consolidated Balance Sheets.
The fair value of leases acquired and, for the 2019 Asset Exchange Transaction, the fair value of the liability for the reimbursement of certain firm gathering costs were based on inputs that are not observable in the market and, as such, are a Level 3 fair value measurement. See Note 4 for a description of the fair value hierarchy. Key assumptions used in the fair value calculations included market-based prices for comparable acreage and, for the 2019 Asset Exchange Transaction, the net present value of expected payments due for reimbursement.
8. 2020 Divestiture
On May 11, 2020, the Company closed a transaction to sell certain non-strategic assets located in Pennsylvania and West Virginia (the 2020 Divestiture) for an aggregate purchase price of approximately $125 million in cash, subject to customary purchase price adjustments and the Contingent Consideration defined and discussed below. The Pennsylvania assets sold included 80 Marcellus wells and approximately 33 miles of gathering lines; the West Virginia assets sold included 809 conventional wells and approximately 154 miles of gathering lines. In addition, the 2020 Divestiture relieved the Company of approximately $49 million in asset retirement obligations and other liabilities associated with the sold assets. Proceeds from the sale were used to pay down the Company's term loan facility. See Note 10.
The purchase and sale agreement for the 2020 Divestiture provides for additional cash bonus payments (the Contingent Consideration) payable to the Company of up to $20 million. Such Contingent Consideration is conditioned upon the three-month average of the NYMEX Henry Hub natural gas settlement price relative to stated floor and target price thresholds beginning on August 31, 2020 and ending on November 30, 2022. The Contingent Consideration represents an embedded derivative that is recorded at fair value in the Consolidated Balance Sheets. The Contingent Consideration had a fair value of approximately $8.2 million and $1.9 million as of December 31, 2021 and 2020, respectively. During the years ended December 31, 2021 and 2020, the Company received cash from the Contingent Consideration of $10.6 million and $0.9 million, respectively. Changes in fair value are recorded in (gain) loss/impairment on sale/exchange of long-lived assets in the Statements of Consolidated Operations. The fair value of the Contingent Consideration is based on significant inputs that are interpolated from observable market data and, as such, is a Level 2 fair value measurement. See Note 4 for a description of the fair value hierarchy.
As a result of the 2020 Divestiture, the Company recognized a net loss of $39.1 million, including the impact of the change in fair value of the Contingent Consideration, in (gain) loss/impairment on sale/exchange of long-lived assets in the Statement of Consolidated Operations during the year ended December 31, 2020.
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9. Income Taxes
The following table summarizes income tax (benefit) expense.
Years Ended December 31, | |||||||||||||||||
2021 | 2020 | 2019 | |||||||||||||||
(Thousands) | |||||||||||||||||
Current: | |||||||||||||||||
Federal | $ | 911 | $ | (132,625) | $ | (106,487) | |||||||||||
State | (1,478) | (10,393) | 5,774 | ||||||||||||||
Subtotal | (567) | (143,018) | (100,713) | ||||||||||||||
Deferred: | |||||||||||||||||
Federal | (316,364) | (129,131) | (213,397) | ||||||||||||||
State | (111,106) | (23,144) | (61,666) | ||||||||||||||
Subtotal | (427,470) | (152,275) | (275,063) | ||||||||||||||
Total income tax benefit | $ | (428,037) | $ | (295,293) | $ | (375,776) |
For the year ended December 31, 2021, the current federal and state income tax benefit related primarily to the sale of state research and development credits. For the year ended December 31, 2020, the current federal and state income tax benefit consisted primarily of refunds of $117 million, including interest, related to the Company's alternative minimum tax (AMT) credit carryforward, the Tax Cuts and Jobs Act of 2017 (the Tax Cuts and Jobs Act) and the acceleration of the receipt of such refunds with the Coronavirus Aid, Relief and Economic Security Act (CARES Act). The remainder of the tax benefit of $26 million, including interest, was related to federal and state audits that were settled in 2020. For the year ended December 31, 2019, the current U.S. federal income tax benefit consisted primarily of expected refunds of $120 million related to the Company's AMT credit carryforward and the Tax Cuts and Jobs Act.
On December 22, 2017, the U.S. Congress enacted the Tax Cuts and Jobs Act, which made significant changes to U.S. federal income tax law, including lowering the federal corporate tax rate to 21% from 35% and repealing the AMT beginning January 1, 2018. In connection with repealing the AMT, the Tax Cuts and Jobs Act also provided that existing AMT credit carryforwards can be used to offset current federal taxes owed with 50% of any remaining balance being refunded in tax years 2018 through 2020. With the passing of the CARES Act, the Company was able to accelerate these refunds to 2020. As a result of an IRS announcement in January 2019 that reversed its position that AMT refunds were subject to sequestration by the federal government at a rate equal to 6.2% of the refund, the Company reversed the related valuation allowance of $13 million in the first quarter of 2019.
The Tax Cuts and Jobs Act limited the deductibility of interest expense, and, as a result, the Company recorded a valuation allowance in 2019 for a portion of the interest expense limit imposed for separate company state income tax purposes. During 2020, final regulations were issued that provided clarity on several issues that were beneficial to the Company, including (i) the exclusion of commitment fees and debt issuance costs from the definition of interest and (ii) the inclusion of the adding back depreciation, depletion and amortization associated with cost of goods sold to arrive at adjusted taxable income. These changes eliminated the interest expense limitation for the Company and the related valuation allowance was reversed in 2020.
The Company has federal net operating loss (NOLs) carryforwards related to its 2017 acquisition of Rice Energy Inc. and NOLs generated in 2017 in excess of amounts carried back to prior years. The Company also has NOLs acquired in the Company's 2016 acquisition of Trans Energy, Inc., of which a nominal amount is available for use annually over the next 15 years. The Tax Cuts and Jobs Act limited the utilization of NOLs generated after December 31, 2017 that have been carried forward into future years to 80% of taxable income and eliminated the ability to carry NOLs back to earlier tax years for refunds of taxes paid. NOLs generated in 2018 and in future periods can be carried forward indefinitely. As a result of the CARES Act, NOLs generated in 2018, 2019 and 2020 can be carried back five years and are allowed to fully offset taxable income ignoring the 80% limitation if utilized prior to 2021.
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Income tax benefit from continuing operations differed from amounts computed at the federal statutory rate of 21% on pre-tax income for reasons summarized below.
Years Ended December 31, | |||||||||||||||||
2021 | 2020 | 2019 | |||||||||||||||
(Thousands) | |||||||||||||||||
Tax at statutory rate | $ | (329,603) | $ | (263,361) | $ | (335,469) | |||||||||||
State income taxes | (119,881) | (73,976) | (119,659) | ||||||||||||||
Valuation allowance | 20,974 | 106,548 | 81,522 | ||||||||||||||
Tax settlements | — | (33,384) | — | ||||||||||||||
Federal and state tax credits | (3,079) | (11,628) | (7,908) | ||||||||||||||
Other | 3,552 | (19,492) | 5,738 | ||||||||||||||
Income tax benefit | $ | (428,037) | $ | (295,293) | $ | (375,776) | |||||||||||
Effective tax rate | 27.3 | % | 23.5 | % | 23.5 | % |
The Company's effective tax rate for the year ended December 31, 2021 was higher compared to the U.S. federal statutory rate due primarily to state taxes, partly offset by valuation allowances that limit certain federal and state tax benefits as well as the West Virginia tax legislation enacted on April 13, 2021 that changed the way taxable income is apportioned in West Virginia for tax years beginning on or after January 1, 2022. The Company's effective tax rate for the year ended December 31, 2020 was higher compared to the U.S. federal statutory rate due primarily to state income taxes and federal and state income tax settlements, partly offset by valuation allowances that limit certain federal and state tax benefits. The Company's effective tax rate for the year ended December 31, 2019 was higher compared to the U.S. federal statutory rate due primarily to state income taxes and the release of the valuation allowance related to AMT sequestration, partly offset by valuation allowances that limit certain state tax benefits.
The Company believes that it is more likely than not that the benefit from certain state NOL carryforwards and certain federal NOLs acquired in recent acquisitions will not be realized. A valuation allowance is required when it is more likely than not that all or a portion of a deferred tax asset will not be realized. All available evidence, both positive and negative, must be considered in determining the need for a valuation allowance. At December 31, 2021, 2020 and 2019, positive evidence considered included the reversals of financial-to-tax temporary differences, the implementation of and/or ability to employ various tax planning strategies and the estimation of future taxable income. Negative evidence considered included historical pre-tax book losses of the Company. A review of positive and negative evidence regarding these tax benefits resulted in the conclusion that valuation allowances for certain NOLs were warranted as it was more likely than not that the Company would not use them prior to expiration. Uncertainties such as future commodity prices can affect the Company's calculations and its ability to use these NOLs prior to expiration. Further, because of the Tax Cuts and Jobs Act, the Company recorded a write-off of deferred tax assets related to certain executive incentive-based awards to be paid in a future year that will not be deductible.
During 2021, the Company released some of the valuation allowance previously recorded due to unrealized gains recognized during the year and the partial sale of its investment in Equitrans Midstream that resulted in a capital loss that will be carried back to offset capital gains recognized in an earlier year. During 2020 and 2019, the Company recorded a partial valuation allowance against a deferred tax asset related to the unrealized loss recorded on its investment in Equitrans Midstream that it does not believe it will be able to utilize due to limitations imposed on capital losses. The Company provided a valuation allowance on the portion in excess of the carryback. Management will continue to assess the potential for realizing deferred tax assets based on the feasibility of future tax planning strategies and may record adjustments to the related valuation allowances in future periods that could materially impact net income.
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The following table reconciles the beginning and ending amount of reserve for uncertain tax positions, excluding interest and penalties.
2021 | 2020 | 2019 | |||||||||||||||
(Thousands) | |||||||||||||||||
Balance at January 1 | $ | 175,213 | $ | 259,588 | $ | 315,279 | |||||||||||
Additions for tax positions taken in current year | 4,969 | 5,470 | 19,431 | ||||||||||||||
Additions for tax positions taken in prior years | 1,850 | 7,250 | 8,929 | ||||||||||||||
Reductions for tax positions taken in prior years | — | (38,859) | (84,051) | ||||||||||||||
Reductions for tax positions settled with tax authorities | — | (58,236) | — | ||||||||||||||
Balance at December 31 | $ | 182,032 | $ | 175,213 | $ | 259,588 |
Included in the reserve for uncertain tax positions are unrecognized tax benefits of $97.8 million, $91.0 million and $150.9 million that, if recognized, would affect the effective tax rates as of December 31, 2021, 2020 and 2019, respectively. Also included in the reserve are uncertain tax positions of $97.2 million, $90.3 million and $113.7 million for the years ended December 31, 2021, 2020 and 2019, respectively, that were recorded in the Consolidated Balance Sheets as a reduction of the related deferred tax asset for general business credit carryforwards and NOLs. During 2020, the Company adjusted its tax reserves as a result of settling its 2010 to 2012 amended return refund claim with the IRS by (i) reducing the uncertain tax positions and increasing the amount of the deferred tax asset for AMT credits by $14.9 million, (ii) reducing the uncertain tax position offset to the deferred tax asset for Research and Experimentation credits by $35.3 million and (iii) writing down the deferred tax asset by $22.6 million to the settlement amount. In addition, in 2020, the Company settled a dispute related to its 2013 Pennsylvania returns and reduced the uncertain tax positions by $46.9 million and agreed to remit $33.5 million to the Commonwealth of Pennsylvania. During 2019, the Company released $84.0 million of reserves and reinstated the related deferred tax asset for AMT due to settlement of the 2013 amended return refund claim with the IRS.
The Company recognizes interest and penalties related to unrecognized tax benefits in income tax expense. The Company recorded interest and penalties expense (income) of approximately $4.2 million, $(3.8) million and $3.3 million for the years ended December 31, 2021, 2020 and 2019, respectively. Interest and penalties of $15.5 million and $11.4 million were included in the Consolidated Balance Sheets at December 31, 2021 and 2020, respectively.
As of December 31, 2021, the Company believed that, as a result of potential settlements with, or legal or administrative guidance by, relevant taxing authorities or the lapse of applicable statutes of limitation, it is reasonably possible that a decrease of $125.9 million in unrecognized tax benefits related to federal tax positions may be necessary within twelve months.
The Company's consolidated U.S. federal income tax liability has been settled with the IRS through 2013. Periodically, the Company is also the subject of various state income tax examinations. As of December 31, 2021, with few exceptions, the Company is no longer subject to state examinations by tax authorities for years before 2015.
There were no material changes to the Company's methodology for accounting for unrecognized tax benefits during 2021.
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The following table summarizes the source and tax effects of temporary differences between financial reporting and tax bases of assets and liabilities.
December 31, | |||||||||||
2021 | 2020 | ||||||||||
(Thousands) | |||||||||||
Deferred tax assets: | |||||||||||
NOL carryforwards | $ | 948,707 | $ | 789,544 | |||||||
Net unrealized losses | 456,751 | 43,475 | |||||||||
Federal tax credits | 83,244 | 79,846 | |||||||||
Alternative minimum tax credit carryforward | 81,237 | 81,237 | |||||||||
Investment in Equitrans Midstream | 69,159 | 94,689 | |||||||||
Federal and state capital loss carryforward | 32,706 | 28,317 | |||||||||
Incentive compensation and deferred compensation plans | 20,409 | 22,419 | |||||||||
Other | 2,499 | 1,241 | |||||||||
Total deferred tax assets | 1,694,712 | 1,140,768 | |||||||||
Valuation allowances | (550,967) | (529,992) | |||||||||
Net deferred tax asset | 1,143,745 | 610,776 | |||||||||
Deferred tax liabilities: | |||||||||||
Property, plant and equipment | (2,051,051) | (1,945,299) | |||||||||
Total deferred tax liabilities | (2,051,051) | (1,945,299) | |||||||||
Net deferred tax liability | $ | (907,306) | $ | (1,334,523) |
During 2021, net deferred tax liability decreased by $427.2 million compared to 2020 due primarily to unrealized mark to market losses and net operating losses for federal and state, partly offset by increased tax depreciation in excess of book depreciation and the Company's investment in Equitrans Midstream.
As of December 31, 2021, the Company had a deferred tax asset of $244.0 million, subject to a valuation allowance of $22.8 million, related to tax benefits from federal NOL carryforwards generated prior to 2018 and expiring between 2035 and 2037. Federal NOLs generated in 2018 and thereafter are represented by a deferred tax asset of $190.0 million and will carryforward indefinitely but will be limited to offset 80% of taxable income in each year. As of December 31, 2021, the Company had a deferred tax asset of $514.7 million, subject to a valuation allowance of $426.2 million, related to tax benefits from state NOL carryforwards with expiration dates ranging from 2021 to 2041 with some being carried forward indefinitely. Due to a decrease in state apportionment rates and impairment of assets, the Company will have less realizable NOLs in future years on a separate company basis and, as such, as of December 31, 2021 the Company had a valuation allowance recorded on its property, plant and equipment state deferred tax asset of $0.3 million. In 2021, the Company incurred an unrealized gain and sold a portion of its investment in Equitrans Midstream, which generated a capital loss that will be carried back to offset capital gains recognized in an earlier year. This investment is a capital asset for tax purposes, and capital losses can only be utilized to offset a capital gain and are limited to being carried back 3 years and forward 5 years for potential utilization. Due to these limitations, the Company also recorded a valuation allowance for the portion of the capital loss recognized in excess of the carryback and any net unrealized losses against the deferred tax asset for its retained equity stake of Equitrans Midstream of $57.5 million for separate company state income tax reporting purposes and $44.0 million for federal income tax reporting purposes.
As of December 31, 2020, the Company had a deferred tax asset of $233.2 million, subject to a valuation allowance of $22.8 million, related to tax benefits from federal NOL carryforwards generated prior to 2018 and expiring between 2035 and 2037. Federal NOLs generated in 2018 and thereafter are represented by a deferred tax asset of $75.6 million and will carryforward indefinitely but will be limited to offset 80% of taxable income in each year. As of December 31, 2020, the Company had a deferred tax asset of $480.8 million, subject to a valuation allowance of $387.7 million, related to tax benefits from state NOL carryforwards with expiration dates ranging from 2021 to 2040. Due to a decrease in state apportionment rates and impairment of assets, the Company will have less realizable NOLs in future years on a separate company basis and, as such, in 2020 recorded a valuation allowance on its property, plant and equipment state deferred tax asset of $0.6 million. In 2020, the Company incurred an unrealized loss on its investment in Equitrans Midstream. This investment is a capital asset for tax purposes, and capital losses can only be utilized to offset a capital gain and are limited to being carried back three years and forward five years for potential utilization. Due to these limitations, the Company also recorded a valuation allowance on the
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deferred tax asset for its retained equity stake of Equitrans Midstream of $62.4 million for separate company state income tax reporting purposes and $56.4 million for federal income tax reporting purposes.
On November 12, 2018, the Company completed the separation of its midstream business, which was composed of the separately operated natural gas gathering, transmission and storage and water services businesses of the Company, from its upstream business, which is composed of the natural gas, NGLs and oil development, production and sales and commercial operations of the Company (the Separation). The Separation was effected by the transfer of the midstream business from the Company to Equitrans Midstream and the distribution of 80.1% of the outstanding shares of Equitrans Midstream's common stock to the Company's shareholders (the Distribution).
For the year ended December 31, 2019, the Company recorded a $90.9 million adjustment to retained earnings and additional paid-in-capital related to the Separation and Distribution. The Separation and Distribution resulted in the recognition of a tax gain related to a pre-Separation transaction. Recognition occurred as a result of Equitrans Midstream exiting the Company's consolidated federal filing group. The gain amount reported in the tax return was different than the amount estimated in the 2018 financial statements; therefore, the Company recorded a return-to-provision adjustment in 2019. This adjustment impacts the amount of deferred taxes transferred to Equitrans Midstream as of the Separation and Distribution date of November 12, 2018.
10. Debt
December 31, 2021 | December 31, 2020 | ||||||||||||||||||||||||||||||||||
Principal Value | Carrying Value (a) | Fair Value (b) | Principal Value | Carrying Value (a) | Fair Value (b) | ||||||||||||||||||||||||||||||
(Thousands) | |||||||||||||||||||||||||||||||||||
Credit Facility expires July 31, 2023 | $ | — | $ | — | $ | — | $ | 300,000 | $ | 300,000 | $ | 300,000 | |||||||||||||||||||||||
Senior notes: | |||||||||||||||||||||||||||||||||||
8.81% to 9.00% series A notes due 2020 – 2021 | — | — | — | 24,000 | 24,000 | 25,232 | |||||||||||||||||||||||||||||
4.875% notes due November 15, 2021 | — | — | — | 125,118 | 124,943 | 128,231 | |||||||||||||||||||||||||||||
3.00% notes due October 1, 2022 | 568,823 | 567,909 | 576,969 | 568,823 | 566,689 | 578,055 | |||||||||||||||||||||||||||||
7.42% series B notes due 2023 | 10,000 | 10,000 | 10,327 | 10,000 | 10,000 | 10,038 | |||||||||||||||||||||||||||||
6.625% notes due February 1, 2025 (c) | 1,000,000 | 994,643 | 1,133,000 | 1,000,000 | 992,905 | 1,146,250 | |||||||||||||||||||||||||||||
1.75% convertible notes due May 1, 2026 | 499,991 | 487,543 | 854,985 | 500,000 | 484,857 | 587,385 | |||||||||||||||||||||||||||||
3.125% notes due May 15, 2026 | 500,000 | 493,157 | 516,265 | — | — | — | |||||||||||||||||||||||||||||
7.75% debentures due July 15, 2026 | 115,000 | 112,721 | 138,504 | 115,000 | 112,224 | 137,025 | |||||||||||||||||||||||||||||
3.90% notes due October 1, 2027 | 1,250,000 | 1,243,340 | 1,344,688 | 1,250,000 | 1,242,182 | 1,249,400 | |||||||||||||||||||||||||||||
5.00% notes due January 15, 2029 | 350,000 | 344,835 | 389,428 | 350,000 | 344,106 | 371,469 | |||||||||||||||||||||||||||||
7.500% notes due February 1, 2030 (c) | 750,000 | 744,417 | 966,983 | 750,000 | 743,726 | 924,510 | |||||||||||||||||||||||||||||
3.625% notes due May 15, 2031 | 500,000 | 492,669 | 523,620 | — | — | — | |||||||||||||||||||||||||||||
Note payable to EQM | 99,838 | 99,838 | 117,837 | 105,056 | 105,056 | 130,464 | |||||||||||||||||||||||||||||
Total debt | 5,643,652 | 5,591,072 | 6,572,606 | 5,097,997 | 5,050,688 | 5,588,059 | |||||||||||||||||||||||||||||
Less: Current portion of debt | 1,074,332 | 1,060,970 | 1,439,165 | 154,336 | 154,161 | 159,943 | |||||||||||||||||||||||||||||
Long-term debt | $ | 4,569,320 | $ | 4,530,102 | $ | 5,133,441 | $ | 4,943,661 | $ | 4,896,527 | $ | 5,428,116 |
(a)For the Company's credit facility and note payable to EQM, the principal value represents the carrying value. For all other debt, the principal value less the unamortized debt issuance costs and debt discounts represents the carrying value.
(b)The carrying value of borrowings under the Company's credit facility approximates fair value as the interest rate is based on prevailing market rates; therefore, it is a Level 1 fair value measurement. For the Company's note payable to EQM, fair value is measured using Level 3 inputs. For all other debt, fair value is measured using Level 2 inputs. See Note 4 for a description of the fair value hierarchy.
(c)Interest rates for the Adjustable Rate Notes (defined below) are as of December 31, 2021. For the notes due February 1, 2025 and the notes due February 1, 2030, the interest rates were 7.875% and 8.750%, respectively, as of December 31, 2020.
Credit Facility. The Company has a $2.5 billion credit facility. On April 23, 2021, the Company entered into an Extension Agreement and First Amendment to Second Amended and Restated Credit Agreement (the Extension Agreement and First Amendment), amending the Second Amended and Restated Credit Agreement, dated as of July 31, 2017, among the Company,
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PNC Bank, National Association, as administrative agent, swing line lender and an L/C issuer, and the other lenders party thereto (the Credit Agreement). The Extension Agreement and First Amendment, among other things, (i) extends the maturity date of the commitments and loans under the Credit Agreement from July 31, 2022 to July 31, 2023, (ii) adds customary provisions to provide for the eventual replacement of LIBOR as a benchmark interest rate and (iii) adds an additional pricing level for the Applicable Rate (as defined in the Extension Agreement and First Amendment).
The Company is permitted to request one additional one-year extension of the expiration date, the approval of which is subject to satisfaction of certain conditions. The Company may, on a one-time basis, request that the lenders' commitments be increased to an aggregate of up to $3.0 billion, subject to certain terms and conditions. Each lender in the facility may decide if it will increase its commitment. The credit facility may be used for working capital, capital expenditures, share repurchases and any other lawful corporate purposes. The credit facility is underwritten by a syndicate of 17 financial institutions, each of which is obligated to fund its pro-rata portion of any borrowings by the Company.
Under the terms of the credit facility, the Company may obtain base rate loans or Eurodollar rate loans denominated in U.S. dollars. Base rate loans bear interest at a Base Rate (as defined in the Extension Agreement and First Amendment) plus a margin based on the Company's then current credit ratings. Eurodollar rate loans bear interest at a Eurodollar Rate (as defined in the Extension Agreement and First Amendment) plus a margin based on the Company's then current credit ratings.
The Company is not required to maintain compensating bank balances. The Company's debt issuer credit ratings, as determined by Moody's, S&P or Fitch on its non-credit-enhanced, senior unsecured long-term debt, determine the level of fees associated with the credit facility in addition to the interest rate charged by the lenders on any amounts borrowed against the credit facility; the lower the Company's debt credit rating, the higher the level of fees and borrowing rate.
The Company's credit facility contains various provisions that, if not complied with, could result in termination of the credit facility, require early payment of amounts outstanding or similar actions. The most significant covenants and events of default under the credit facility are the maintenance of a debt-to-total capitalization ratio and limitations on transactions with affiliates. The credit facility contains financial covenants that require a total debt-to-total capitalization ratio of no greater than 65%. As of December 31, 2021, the Company was in compliance with all debt provisions and covenants.
The Company had approximately $440 million and $791 million of letters of credit outstanding under its credit facility as of December 31, 2021 and 2020, respectively.
Under the Company's credit facility, for the years ended December 31, 2021, 2020 and 2019, the maximum amounts of outstanding borrowings were $1.7 billion, $0.7 billion and $1.1 billion, respectively, the average daily balances were approximately $609 million, $148 million and $340 million, respectively, and interest was incurred at weighted average annual interest rates of 1.9%, 2.3% and 3.8%, respectively. For the years ended December 31, 2021, 2020 and 2019, the Company incurred commitment fees of approximately 28, 28 and 20 basis points, respectively, on the undrawn portion of its credit facility to maintain credit availability.
Senior Notes. The indentures governing the Company's long-term indebtedness contain certain restrictive financial and operating covenants, including covenants that restrict, among other things, the Company's ability to incur, as applicable, indebtedness, incur liens, enter into sale and leaseback transactions, complete acquisitions, merge, sell assets and perform certain other corporate actions. Certain of the Company's senior notes also include an offer to repurchase provision applicable upon the occurrence of certain change of control events specified in the applicable indentures. Interest rates on the Company's $1.0 billion aggregate principal amount of senior notes due February 1, 2025 and $750 million aggregate principal amount of senior notes due February 1, 2030 (together, the Adjustable Rate Notes) fluctuate based on changes to the credit ratings assigned to the Company's senior notes by Moody's, S&P and Fitch. Interest rates on the Company's other outstanding senior notes do not fluctuate based on changes to the credit ratings assigned to its senior notes by Moody's, S&P and Fitch.
As of December 31, 2021, aggregate maturities for the Company's senior notes were $569 million in 2022, $10 million in 2023, zero in 2024, $1,000 million in 2025, $1,115 million in 2026 and $2,850 million thereafter.
3.125% Senior Notes and 3.625% Senior Notes. On May 17, 2021, the Company issued $500 million aggregate principal amount of 3.125% senior notes due May 15, 2026 and $500 million aggregate principal amount of 3.625% senior notes due May 15, 2031. After deducting offering costs of $15.6 million, net proceeds from the sale of the notes of $984.4 million were used to partly fund the Alta Acquisition described in Note 6. The covenants of the 3.125% senior notes and 3.625% senior notes are consistent with the Company's existing senior unsecured notes; provided, however, that the 3.125% senior notes and 3.625% senior notes include an offer to repurchase provision applicable upon the occurrence of certain change of control events specified in the applicable indentures.
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Debt Repayments. On February 1, 2021, the Company redeemed the remaining $125.1 million aggregate principal amount of the its 4.875% senior notes at a total cost of $130.7 million, inclusive of redemption premiums of $4.3 million and accrued but unpaid interest of $1.3 million.
In January 2022, the Company redeemed $206.0 million aggregate principal amount of the its 3.00% senior notes at a total cost of $210.4 million, inclusive of redemption premiums of $2.6 million and accrued but unpaid interest of $1.8 million.
Term Loan Facility. The Company had a $1.0 billion term loan facility that was scheduled to mature in May 2021. On June 30, 2020, the Company used proceeds from the offering of its Convertible Notes (see below), cash from its income tax refunds (see Note 9) and proceeds from the 2020 Divestiture (described in Note 8) to fully repay its term loan facility. Under the Company's term loan facility, for the period beginning January 1, 2020 and ending June 30, 2020, the average daily balance was approximately $692 million and interest was incurred at a weighted average annual interest rate of 2.6%. For the period May 31, 2019 through December 31, 2019, the average daily balance was $1.0 billion and interest was incurred at a weighted average annual interest rate of 3.1%.
Note Payable to EQM. EQM owns a preferred interest in EQT Energy Supply, LLC, a subsidiary of the Company, that is accounted for as a note payable due to the terms of the operating agreement of EQT Energy Supply, LLC. The fair value of the note payable to EQM is a Level 3 fair value measurement and is estimated using an income approach model using a market-based discount rate. Principal amounts due for the note payable to EQM are $5.5 million in 2022, $5.8 million in 2023, $6.3 million in 2024, $6.5 million in 2025, $6.9 million in 2026 and $68.8 million thereafter.
Surety Bonds. The Company had approximately $245 million and $93 million of surety bonds outstanding as of December 31, 2021 and 2020, respectively, in response to its credit downgrades by Moody's, S&P and Fitch.
Convertible Notes. In April 2020, the Company issued $500 million aggregate principal amount of 1.75% convertible senior notes (the Convertible Notes) due May 1, 2026 unless earlier redeemed, repurchased or converted. The Convertible Notes were issued in a private offering to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, as amended. After deducting offering costs of $16.9 million, net proceeds from the sale of the Convertible Notes of $483.1 million were used to repay the term loan facility. The effective interest rate for the Convertible Notes is 2.4%.
Holders of the Convertible Notes may convert their Convertible Notes, at their option, at any time prior to the close of business on January 30, 2026 under the following circumstances:
•during any quarter as long as the last reported price of EQT common stock for at least 20 trading days (consecutive or otherwise) during the period of 30 consecutive trading days ending on the last trading day of the immediately preceding quarter is greater than or equal to 130% of the conversion price on each such trading day (the Sale Price Condition);
•during the five-business-day period after any five-consecutive-trading-day period (the measurement period) in which the trading price per $1,000 principal amount of the Convertible Notes for each trading day of the measurement period is less than 98% of the product of the last reported price of EQT common stock and the conversion rate for the Convertible Notes on each such trading day;
•if the Company calls any or all of the Convertible Notes for redemption, at any time prior to the close of business on the second scheduled trading day immediately preceding such redemption date; and
•upon the occurrence of certain corporate events set forth in the Convertible Notes indenture.
On or after February 1, 2026, holders of the Convertible Notes may convert their Convertible Notes, at their option, at any time until the close of business on the second scheduled trading date immediately preceding May 1, 2026.
The initial conversion rate for the Convertible Notes is 66.6667 shares of EQT common stock per $1,000 principal amount of the Convertible Notes, which is equivalent to an initial conversion price of $15.00 per share of EQT common stock. The initial conversion price represents a premium of 20% to the $12.50 per share closing price of EQT common stock on April 23, 2020. The conversion rate is subject to adjustment under certain circumstances. In addition, following certain corporate events that occur prior to May 1, 2026 or if the Company delivers notice of redemption, the Company will, in certain circumstances, increase the conversion rate for a holder who elects to convert its Convertible Notes in connection with such corporate event or notice of redemption. Upon conversion of the remaining outstanding Convertible Notes, the Company may satisfy its conversion obligation by paying and/or delivering at the Company's election, in the manner and subject to the terms and conditions provided in the Convertible Notes indenture, cash, shares of EQT common stock or a combination thereof.
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Pursuant to the terms of the Convertible Notes indenture, the Sale Price Condition for conversion of the Convertible Notes was satisfied as of June 30, 2021, and, accordingly, holders of Convertible Notes were permitted to convert any of their Convertible Notes, at their option, at any time during the quarter beginning on July 1, 2021 and ending on September 30, 2021, subject to all terms and conditions set forth in the Convertible Notes indenture. During the three months ended September 30, 2021, holders of the Convertible Notes exercised their conversion right with respect to $9 thousand in aggregate principal amount of the Convertible Notes. The Company elected to settle all such conversions by issuing to the converting holders of the Convertible Notes 599 shares of EQT common stock in the aggregate at an average conversion price of $19.64.
The Sale Price Condition for conversion of the Convertible Notes was not satisfied as of September 30, 2021, and, accordingly, holders of Convertible Notes were not permitted to convert any of their Convertible Notes during the three months ended December 31, 2021.
The Sale Price Condition for conversion of the Convertible Notes was satisfied as of December 31, 2021 and, accordingly, holders of Convertible Notes may convert any of their Convertible Notes, at their option, at any time during the quarter beginning on January 1, 2022 and ending on March 31, 2022, subject to all terms and conditions set forth in the Convertible Notes indenture. Therefore, as of December 31, 2021, the net carrying value of the Convertible Notes was included in current portion of debt on the Consolidated Balance Sheet.
Upon conversion of the remaining outstanding Convertible Notes, the Company intends to use a combined settlement approach to satisfy its 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.
The Company may not redeem the Convertible Notes prior to May 5, 2023. On or after May 5, 2023 and prior to February 1, 2026, the Company may redeem for cash all or any portion of the Convertible Notes, at its option, at a redemption price equal to 100% of the principal amount of the Convertible Notes to be redeemed plus accrued and unpaid interest up to the redemption date as long as the last reported price per share of EQT common stock has been at least 130% of the conversion price in effect for at least 20 trading days (consecutive or otherwise) during any 30-consecutive-trading-day period ending on the trading day immediately preceding the date on which the Company delivers notice of redemption. A sinking fund is not provided for the Convertible Notes.
In connection with the Convertible Notes offering, the Company entered into privately negotiated capped call transactions (the Capped Call Transactions), the purpose of which is to reduce the potential dilution to EQT common stock upon conversion of the Convertible Notes and/or offset any cash payments the Company is required to make in excess of the principal amount of such obligation, with such reduction and offset subject to a cap. The Capped Call Transactions have an initial strike price of $15.00 per share of EQT common stock and an initial capped price of $18.75 per share of EQT common stock, each of which are subject to certain customary adjustments.
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 of $32.5 million was recorded as a reduction to equity and will not be remeasured.
The table below summarizes the net carrying amount of the Convertible Notes, including the unamortized debt issuance costs.
December 31, | |||||||||||
2021 | 2020 | ||||||||||
(Thousands) | |||||||||||
Principal | $ | 499,991 | $ | 500,000 | |||||||
Less: Unamortized debt issuance costs | 12,448 | 15,143 | |||||||||
Net carrying value of Convertible Notes | $ | 487,543 | $ | 484,857 |
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The table below summarizes the components of interest expense related to the Convertible Notes.
Years Ended December 31, | |||||||||||||||||
2021 | 2020 | ||||||||||||||||
(Thousands) | |||||||||||||||||
Contractual interest expense | $ | 8,750 | $ | 5,906 | |||||||||||||
Amortization of issuance costs | 2,695 | 1,777 | |||||||||||||||
Total Convertible Notes interest expense | $ | 11,445 | $ | 7,683 |
Based on the closing stock price of EQT common stock of $21.81 on December 31, 2021 and excluding the impact of the Capped Call Transactions, the if-converted value of the Convertible Notes exceeded the principal amount by $227 million.
ASU 2020-06 Adoption. As discussed in Note 1, the Company adopted ASU 2020-06 effective as of January 1, 2022 using the full retrospective method of adoption. The following tables present the impact of the adoption of this ASU on the Company's previously reported historical results for the periods presented.
Year Ended December 31, 2021 | |||||||||||||||||
As Reported | ASU 2020-06 Adoption Adjustment | As Adjusted | |||||||||||||||
(Thousands, except per share amounts) | |||||||||||||||||
Interest expense | $ | 308,903 | $ | (19,150) | $ | 289,753 | |||||||||||
Income tax benefit | (434,175) | 6,138 | (428,037) | ||||||||||||||
Net loss | (1,154,513) | 13,012 | (1,141,501) | ||||||||||||||
Less: Net income (loss) attributable to noncontrolling interest | 1,246 | — | 1,246 | ||||||||||||||
Net loss attributable to EQT Corporation | $ | (1,155,759) | $ | 13,012 | $ | (1,142,747) | |||||||||||
Basic and diluted: | |||||||||||||||||
Weighted average common stock outstanding (a) | 323,196 | — | 323,196 | ||||||||||||||
Net loss per share of common stock attributable to EQT Corporation | $ | (3.58) | $ | 0.04 | $ | (3.54) |
(a)For the year ended December 31, 2021, diluted weighted average common stock outstanding did not change because the potentially dilutive securities had an anti-dilutive effect on loss per share.
Year Ended December 31, 2020 | |||||||||||||||||
As Reported | ASU 2020-06 Adoption Adjustment | As Adjusted | |||||||||||||||
(Thousands, except per share amounts) | |||||||||||||||||
Interest expense | $ | 271,200 | $ | (11,932) | $ | 259,268 | |||||||||||
Income tax benefit | (298,858) | 3,565 | (295,293) | ||||||||||||||
Net loss | (967,176) | 8,367 | (958,809) | ||||||||||||||
Less: Net income (loss) attributable to noncontrolling interest | (10) | — | (10) | ||||||||||||||
Net loss attributable to EQT Corporation | $ | (967,166) | $ | 8,367 | $ | (958,799) | |||||||||||
Basic and diluted: | |||||||||||||||||
Weighted average common stock outstanding (a) | 260,613 | — | 260,613 | ||||||||||||||
Net loss per share of common stock attributable to EQT Corporation | $ | (3.71) | $ | 0.03 | $ | (3.68) |
(a)For the year ended December 31, 2020, diluted weighted average common stock outstanding did not change because the potentially dilutive securities had an anti-dilutive effect on loss per share.
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December 31, 2021 | |||||||||||||||||
As Reported | ASU 2020-06 Adoption Adjustment | As Adjusted | |||||||||||||||
(Thousands) | |||||||||||||||||
Current portion of debt (a) | $ | 954,900 | $ | 106,070 | $ | 1,060,970 | |||||||||||
Deferred income taxes | 938,612 | (31,306) | 907,306 | ||||||||||||||
Common stock, no par value | 10,167,963 | (96,143) | 10,071,820 | ||||||||||||||
Accumulated deficit | (115,779) | 21,379 | (94,400) |
(a)Pursuant to the terms of the Company's convertible senior notes indenture, a sale price condition for conversion of the convertible notes was satisfied as of December 31, 2021, and, accordingly, holders of convertible notes were permitted to convert any of their convertible notes, at their option, at any time during the three months ended March 31, 2022, subject to all terms and conditions set forth in the convertible notes indenture. Therefore, as of December 31, 2021, the net carrying value of the Company's convertible notes was included in current portion of debt in the Consolidated Balance Sheet.
December 31, 2020 | |||||||||||||||||
As Reported | ASU 2020-06 Adoption Adjustment | As Adjusted | |||||||||||||||
(Thousands) | |||||||||||||||||
Senior notes | $ | 4,371,467 | $ | 125,222 | $ | 4,496,689 | |||||||||||
Deferred income taxes | 1,371,967 | (37,444) | 1,334,523 | ||||||||||||||
Common stock, no par value | 8,241,684 | (96,145) | 8,145,539 | ||||||||||||||
Retained earnings | 1,048,259 | 8,367 | 1,056,626 |
Certain line items in the Statements of Consolidated Cash Flows were adjusted to reflect the impact of the adoption of ASU 2020-06; however, the adoption did not impact cash and did not change net cash provided by operating, investing or financing activities.
11. Common Stock
As of December 31, 2021, the Company had reserved 5.5 million shares of authorized and unissued EQT common stock for stock compensation plans and approximately 40 million shares of authorized and unissued EQT common stock for settlement of the Convertible Notes.
In December 2021, the Company announced that the Board of Directors approved a share repurchase program to repurchase shares of its common stock for an aggregate purchase price up to $1 billion. The share repurchase authority is valid through December 31, 2023. In December 2021, the Company repurchased 1,361,668 shares of EQT common stock for an aggregate purchase price of $29.4 million at an average price of $21.56 per share, excluding fees and broker commissions, under this share repurchase program.
In July 2021, the Company issued 98,789,388 shares of EQT common stock as part of the consideration for the Alta Acquisition described in Note 6.
In October 2020, the Company entered into an underwriting agreement under which the Company sold 20,000,000 shares of EQT common stock at a price to the public of $15.50 per share. In November 2020, the option to purchase 3,000,000 additional shares was exercised by the underwriters on the same terms. After deducting offering costs of $15.6 million, the net proceeds of $340.9 million were used to fund a portion of the purchase price of the Chevron Acquisition described in Note 6.
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12. Changes in Accumulated Other Comprehensive Loss by Component
The following table explains the changes in accumulated other comprehensive loss by component.
Interest rate cash flow hedges, net of tax | Other postretirement benefits liability adjustment, net of tax | Accumulated other comprehensive loss, net of tax | |||||||||||||||
(Thousands) | |||||||||||||||||
December 31, 2018 | $ | (387) | $ | (5,019) | $ | (5,406) | |||||||||||
Losses reclassified from accumulated other comprehensive loss, net of tax | 387 | (a) | 316 | (b) | 703 | ||||||||||||
Change in accounting principle | — | (496) | (496) | ||||||||||||||
December 31, 2019 | — | (5,199) | (5,199) | ||||||||||||||
Gains reclassified from accumulated other comprehensive loss, net of tax | — | (156) | (b) | (156) | |||||||||||||
December 31, 2020 | — | (5,355) | (5,355) | ||||||||||||||
Losses reclassified from accumulated other comprehensive loss, net of tax | — | 744 | (b) | 744 | |||||||||||||
December 31, 2021 | $ | — | $ | (4,611) | $ | (4,611) |
(a)Losses, net of tax, related to interest rate cash flow hedges were reclassified from accumulated other comprehensive loss into interest expense.
(b)Losses (gains), net of tax, related to other postretirement benefits liability adjustments were attributable to net actuarial losses/gains and net prior service costs.
13. Share-Based Compensation Plans
The following table summarizes the Company's share-based compensation expense.
Years Ended December 31, | |||||||||||||||||
2021 | 2020 | 2019 | |||||||||||||||
(Thousands) | |||||||||||||||||
Incentive Performance Share Unit Programs | $ | 15,386 | $ | 10,457 | $ | 13,306 | |||||||||||
Value Driver Performance Share Unit Award Programs | — | 885 | 3,376 | ||||||||||||||
Restricted stock awards | 19,217 | 10,480 | 14,430 | ||||||||||||||
Non-qualified stock options | 550 | 848 | 4,774 | ||||||||||||||
Stock appreciation rights | 9,183 | 2,724 | — | ||||||||||||||
Other programs, including non-employee director awards | 3,171 | 2,155 | 2,257 | ||||||||||||||
Total share-based compensation expense (a) | $ | 47,507 | $ | 27,549 | $ | 38,143 |
(a)For the years ended December 31, 2021, 2020 and 2019, share-based compensation expense of $4.7 million, $2.1 million and $28.6 million, respectively, was included in other operating expenses related primarily to reorganization costs.
The Company typically uses treasury stock to fund awards paid in stock, but the Company can elect to fund such awards by stock acquired by the Company in the open market or from any other person, issued directly by the Company or any combination of the foregoing.
There was no cash received from exercises under all share-based payment arrangements for employees and directors for the years ended December 31, 2021, 2020 and 2019. During the years ended December 31, 2021, 2020 and 2019, share-based payment arrangements paid in stock generated tax benefits of $1.3 million, $1.0 million and $2.4 million, respectively.
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In connection with the Separation in 2018, the Company transferred obligations related to then-outstanding share-based compensation awards to Equitrans Midstream. To preserve the aggregate fair value of awards held prior to the Separation, as measured immediately before and immediately after the Separation, each holder of share-based compensation awards generally received an adjusted award consisting of both a stock-based compensation award denominated in Company equity and a stock-based compensation award denominated in Equitrans Midstream equity. These awards were adjusted in accordance with the basket method, which resulted in participants retaining one unit of the existing Company incentive award and receiving an additional 0.80 units of an Equitrans Midstream-based award. All awards subject to this adjustment were vested as of December 31, 2021.
The Company recognized compensation cost related to unvested awards held by its employees, regardless of who settles the obligation. Upon vesting the Company was obligated to settle all outstanding share-based compensation awards denominated in the Company's equity, regardless of whether the holders were employees of the Company or Equitrans Midstream. Likewise, upon vesting, Equitrans Midstream was obligated to settle all of the outstanding share-based compensation awards denominated in its equity, regardless of whether the holders were employees of Equitrans Midstream or the Company. Changes in performance and number of outstanding awards can impact the ultimate amount of these obligations. Share counts for awards discussed herein represent outstanding shares to be remitted by the Company to its employees and those remitted to employees of Equitrans Midstream. When an award has graduated vesting, the Company records expense equal to the vesting percentage on the vesting date.
Incentive Performance Share Unit Programs – Equity & Liability
The Management Development and Compensation Committee of the Company's Board of Directors (the Compensation Committee) has adopted the following programs:
•2017 Incentive Performance Share Unit Program (2017 Incentive PSU Program) under the 2014 Long-Term Incentive Plan (LTIP);
•2018 Incentive Performance Share Unit Program (2018 Incentive PSU Program) under the 2014 LTIP;
•2019 Incentive Performance Share Unit Program (2019 Incentive PSU Program) under the 2014 LTIP;
•2020 Incentive Performance Share Unit Program (2020 Incentive PSU Program) under the 2019 LTIP; and
•2021 Incentive Performance Share Unit Program (2021 Incentive PSU Program) under the 2020 LTIP.
The programs noted above are collectively referred to as the Incentive PSU Programs. The 2020 Incentive PSU Program and 2021 Incentive PSU Program granted equity awards. The 2017 Incentive PSU Program, 2018 Incentive PSU Program and 2019 Incentive PSU Program granted both equity and liability awards.
The Incentive PSU Programs were established to provide long-term incentive opportunities to executives and key employees to further align their interests with those of the Company's shareholders and with the strategic objectives of the Company. The performance period for each of the awards under the Incentive PSU Programs is 36 months, with vesting occurring upon payment following the expiration of the performance period.
Executive performance incentive program awards granted in year 2017 were earned based on:
•the level of total shareholder return relative to a predefined peer group; and
•the cumulative total sales volume growth, in each case, over the performance period.
Executive performance incentive program awards granted in years 2018 and 2019 were earned based on:
•the level of total shareholder return relative to a predefined peer group;
•the level of operating and development cost improvement; and
•return on capital employed.
Executive performance incentive program awards granted in year 2020 are earned based on:
•adjusted well costs;
•adjusted free cash flow; and
•the level of total shareholder return relative to a predefined peer group.
Executive performance incentive program awards granted in year 2021 are earned based on:
•the level of absolute total shareholder return and total shareholder return relative to a predefined peer group.
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Prior to 2020, the payout factor varied between zero and 300% of the number of outstanding units contingent upon the performance metrics listed above. The 2020 Incentive PSU Program has a payout factor that ranges from zero to 150% and the 2021 Incentive PSU Program has a payout factor that ranges from zero to 200%. The Company recorded the 2020 Incentive PSU Program, the 2021 Incentive PSU Program and the portion of the 2017 Incentive PSU Program, 2018 Incentive PSU Program and 2019 Incentive PSU Program to be settled in stock as equity awards using a grant date fair value determined through a Monte Carlo simulation, which projected the share price for the Company and its peers at the end point of the performance period. The 2017 Incentive PSU Program, 2018 Incentive PSU Program and 2019 Incentive PSU Program also included awards to be settled in cash, which are recorded at fair value as of the measurement date determined through a Monte Carlo simulation, which projected the share price for the Company and its peers at the end point of the performance period. The expected share prices were generated using each company's annual volatility for the expected term and the commensurate three-year risk-free rate shown in the chart below. As the Incentive PSU Programs include a performance condition that affects the number of shares that will ultimately vest, the Monte Carlo simulation computed either the grant date fair value for equity awards or the measurement date fair value for liability awards for each possible performance condition outcome on the grant date for equity awards or the measurement date for liability awards. The Company reevaluates the then-probable outcome at the end of each reporting period to record expense at the probable outcome grant date fair value or measurement date fair value, as applicable. Vesting of the units under each Incentive PSU Program occurs upon payment after the end of the performance period.
The following table summarizes Incentive PSU Programs to be settled in stock and classified as equity awards.
Incentive PSU Programs – Equity Settled | Nonvested Shares (a) | Weighted Average Fair Value | Aggregate Fair Value | |||||||||||||||||
Outstanding at December 31, 2018 | 536,014 | $ | 94.36 | $ | 50,579,160 | |||||||||||||||
Granted | 463,380 | 29.45 | 13,646,541 | |||||||||||||||||
Vested | (384,101) | 96.30 | (36,988,926) | |||||||||||||||||
Outstanding at December 31, 2019 | 615,293 | 44.27 | 27,236,775 | |||||||||||||||||
Granted | 1,376,198 | 6.62 | 9,107,846 | |||||||||||||||||
Vested | (44,573) | 120.60 | (5,375,504) | |||||||||||||||||
Forfeited | (7,190) | 13.28 | (95,483) | |||||||||||||||||
Outstanding at December 31, 2020 | 1,939,728 | 15.92 | 30,873,634 | |||||||||||||||||
Granted | 922,260 | 23.44 | 21,617,038 | |||||||||||||||||
Vested | (107,340) | 76.53 | (8,214,730) | |||||||||||||||||
Outstanding at December 31, 2021 | 2,754,648 | $ | 16.07 | $ | 44,275,942 |
(a)For the years ended December 31, 2021, 2020 and 2019, the Company settled total shares of 9,550, 7,020 and 130,393, respectively, for Equitrans Midstream employees.
The following table summarizes Incentive PSU Programs to be settled in cash and classified as liability awards.
Incentive PSU Programs – Cash Settled | Nonvested Shares (a) | Weighted Average Fair Value | Aggregate Fair Value | |||||||||||||||||
Outstanding at December 31, 2018 | 229,838 | $ | 96.67 | $ | 22,217,645 | |||||||||||||||
Granted | 255,920 | 29.45 | 7,536,844 | |||||||||||||||||
Forfeited | (33,348) | 75.65 | (2,522,819) | |||||||||||||||||
Outstanding at December 31, 2019 | 452,410 | 60.19 | 27,231,670 | |||||||||||||||||
Vested | (93,359) | 120.60 | (11,259,095) | |||||||||||||||||
Forfeited | (19,356) | 61.43 | (1,189,050) | |||||||||||||||||
Outstanding at December 31, 2020 | 339,695 | 43.52 | 14,783,525 | |||||||||||||||||
Vested | (102,175) | 76.53 | (7,819,453) | |||||||||||||||||
Forfeited | (3,940) | 29.45 | (116,033) | |||||||||||||||||
Outstanding at December 31, 2021 | 233,580 | $ | 29.32 | $ | 6,848,039 |
(a)For the years ended December 31, 2021 and 2020, the Company settled total shares paid in cash of 84,697 and 40,018, respectively, for Equitrans Midstream employees.
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Total capitalized compensation costs related to the Incentive PSU Programs for the years ended December 31, 2021, 2020 and 2019 were $0.8 million, $0.9 million and $(0.8) million, respectively. As of December 31, 2021, $3.2 million and $14.9 million of unrecognized compensation cost (assuming no changes to the performance condition achievement level) related to the 2020 Incentive PSU Program and 2021 Incentive PSU Program, respectively, was expected to be recognized over the remainder of the performance periods.
Fair value is estimated using a Monte Carlo simulation valuation method with the following weighted average assumptions at grant date:
Incentive PSU Programs Issued During the Years Ended December 31, | |||||||||||||||||||||||||||||
2021 (a) | 2020 (b) | 2019 | 2018 | 2017 | |||||||||||||||||||||||||
Risk-free rate | 0.18% | 1.22% | 2.44% | 1.97% | 1.47% | ||||||||||||||||||||||||
Volatility factor | 72.50% | 45.41% | 54.60% | 32.60% | 32.30% | ||||||||||||||||||||||||
Expected term | 3 years | 3 years | 3 years | 3 years | 3 years |
(a)There were two grant dates for the 2021 Incentive PSU Program. Amounts shown represent weighted average.
(b)There were three grant dates for the 2020 Incentive PSU Program. Amounts shown represent weighted average.
Dividends paid from the beginning of the performance period will be cumulatively added as additional shares of common stock; therefore, dividend yield is not applicable.
Value Driver Performance Share Unit Award Programs
Historically, the Compensation Committee adopted the following programs:
•2017 Value Driver Performance Share Unit Award Program (2017 EQT VDPSU Program) under the 2014 LTIP;
•2018 Value Driver Performance Share Unit Award Program (2018 EQT VDPSU Program) under the 2014 LTIP; and
•2019 Value Driver Performance Share Unit Award Program (2019 EQT VDPSU Program) under the 2014 LTIP.
The programs noted above are collectively referred to as the VDPSU Programs. The VDPSU Programs were established to align the interests of key employees with the interests of shareholders and customers and the strategic objectives of the Company. Under each VDPSU Program, 50% of the confirmed awards vested upon payment following the first anniversary of the grant date; the remaining 50% of the confirmed awards vested upon payment following the second anniversary of the grant date, subject to continued service through such date. Due to the graded vesting of each award under the VDPSU Programs, the Company recognized compensation cost over the requisite service period for each separately vesting tranche of the award as though each award was, in substance, multiple awards. The payments were contingent upon adjusted earnings before interest, income taxes, depreciation and amortization performance as compared to the Company's annual business plan and individual, business unit and Company value driver performance over the respective one-year periods. The following table provides additional detailed information on each historical award.
VDPSU Program | Accounting Treatment | Weighted Average Fair Value | Cash Paid (Millions) | Awards Outstanding (including Accrued Dividends) as of December 31, 2021 (a) | ||||||||||||||||||||||
2017 | Liability | $ | 65.40 | $ | 14.0 | N/A | ||||||||||||||||||||
$ | 65.40 | $ | 4.0 | N/A | ||||||||||||||||||||||
2018 | Liability | $ | 56.92 | $ | 4.9 | N/A | ||||||||||||||||||||
$ | 56.92 | $ | 1.2 | N/A | ||||||||||||||||||||||
2019 | Liability | $ | 18.89 | $ | 1.7 | N/A | ||||||||||||||||||||
$ | 18.89 | $ | 1.7 | N/A |
(a)The 2017 EQT VDPSU Program and 2018 EQT VDPSU Program included 95,452 and 130,355 awards, respectively, for Equitrans Midstream employees that were settled by the Company.
Total capitalized compensation costs related to the VDPSU Programs for the years ended December 31, 2020 and 2019 was $0.4 million and $2.5 million, respectively. There were no compensation costs related to the VDPSU Programs for the year ended December 31, 2021.
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Restricted Stock Unit Awards – Equity
The Company granted 1,980,230, 1,767,960 and 613,440 restricted stock unit equity awards to employees of the Company during the years ended December 31, 2021, 2020 and 2019, respectively. Awards granted in 2019 will fully vest at the end of the three-year period commencing with the date of grant, assuming continued service through such date, while the 2021 and 2020 awards are subject to a three-year graded vesting schedule, also assuming continued service through such date. For the years ended December 31, 2021, 2020 and 2019, the weighted average fair value of these restricted stock unit grants, based on the grant date fair value of EQT common stock, was approximately $13.92, $10.02 and $17.42, respectively.
The total fair value of restricted stock unit equity awards vested during the years ended December 31, 2021, 2020 and 2019 was $8.6 million, $3.2 million and $11.9 million, respectively. Total capitalized compensation costs related to the restricted stock unit equity awards was $6.7 million and $3.0 million for the years ended December 31, 2021 and 2020, respectively.
As of December 31, 2021, $13.7 million of unrecognized compensation cost related to nonvested restricted stock unit equity awards was expected to be recognized over a remaining weighted average vesting term of approximately 0.9 years.
The following table summarizes restricted stock unit equity award activity as of December 31, 2021.
Restricted Stock – Equity Settled | Nonvested Shares (a) | Weighted Average Fair Value | Aggregate Fair Value | |||||||||||||||||
Outstanding at January 1, 2021 | 1,868,400 | $ | 11.56 | $ | 21,594,314 | |||||||||||||||
Granted | 1,980,230 | 13.92 | 27,563,546 | |||||||||||||||||
Vested | (621,930) | 13.85 | (8,612,563) | |||||||||||||||||
Forfeited | (122,419) | 12.16 | (1,488,862) | |||||||||||||||||
Outstanding at December 31, 2021 | 3,104,281 | $ | 12.58 | $ | 39,056,435 |
(a)Shares vested during the year ended December 31, 2021 included 59,340 shares for an Equitrans Midstream employee that was settled by the Company.
Restricted Stock Unit Awards – Liability
During the year ended December 31, 2019, the Company granted 686,350 restricted stock unit liability awards, respectively, to key employees of the Company that will be paid in cash. The Company did not grant restricted stock unit awards to be paid in cash during the years ended December 31, 2021 and 2020.
Adjusted for forfeitures, there were 417,265 awards outstanding as of December 31, 2021. Because these awards are liability awards, the Company records compensation expense based on the fair value of the awards as remeasured at the end of each reporting period. The restricted stock units granted will be fully vested at the end of the three-year period commencing with the date of grant, assuming continued service through such date. The total liability recorded for these restricted stock units was $8.1 million, $4.5 million and $4.4 million as of December 31, 2021, 2020 and 2019, respectively.
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Non-Qualified Stock Options
The fair value of the Company's option grants was estimated at the grant date using a Black-Scholes option-pricing model with the assumptions indicated in the table below for the years ended December 31, 2020 and 2019. The risk-free rate for periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the date of grant. The dividend yield is based on the dividend yield of EQT common stock at the time of grant. Expected volatilities are based on historical volatility of EQT common stock. The expected term represents the period of time that options granted are expected to be outstanding based on historical option exercise experience. There were no stock options granted in 2021.
Years Ended December 31, | |||||||||||
2020 | 2019 (a) | ||||||||||
Risk-free interest rate | 1.10 | % | 2.48 | % | |||||||
Dividend yield | — | % | 0.46 | % | |||||||
Volatility factor | 60.00 | % | 27.97 | % | |||||||
Expected term | 4 years | 5 years | |||||||||
Number of Options Granted | 1,000,000 | 779,300 | |||||||||
Weighted Average Grant Date Fair Value | $ | 1.61 | $ | 5.31 |
(a)There were two grant dates for the 2019 options. Amount shown represents weighted average.
As of December 31, 2021, $0.2 million of unrecognized compensation cost related to outstanding nonvested stock options was expected to be recognized by December 31, 2023. The total intrinsic value of options exercised during the year ended December 31, 2021 was $0.2 million. There were no stock option exercises in 2020 and 2019.
The following table summarizes option activity as of December 31, 2021.
Non-Qualified Stock Options | Shares | Weighted Average Exercise Price | Weighted Average Remaining Contractual Term | Aggregate Intrinsic Value | ||||||||||||||||||||||
Outstanding at January 1, 2021 | 3,554,729 | $ | 23.20 | |||||||||||||||||||||||
Exercised | (88,100) | 18.89 | ||||||||||||||||||||||||
Outstanding at December 31, 2021 | 3,466,629 | 23.31 | 4.2 years | $ | 13,657,649 | |||||||||||||||||||||
Exercisable at December 31, 2021 | 2,789,062 | $ | 26.51 | 4.0 years | $ | 5,752,488 |
Stock Appreciation Rights
During 2020, the Company granted stock appreciation rights subject to certain performance conditions, such as adjusted well costs and adjusted free cash flow. Once vested, the participant is entitled to receive, upon exercise, a number of shares of EQT’s common stock, cash or a combination of the two, based upon the excess of the fair market value as of the date of exercise over a base price of $10.00.
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The awards are accounted for as liability awards and, as such, compensation expense is recorded based on the fair value of the awards as remeasured at the end of each reporting period using a Black-Scholes option-pricing model with the assumptions indicated in the table below. The risk-free rate is based on the U.S. Treasury yield curve in effect at the reporting date. The dividend yield is based on the dividend yield of EQT common stock at the reporting date, which is set at zero for the stock appreciation rights as the Company declared no dividends during 2021. Expected volatilities are based on a 50-50 blend of the expected term-matched historical volatility as of the valuation date and the weighted-average implied volatility from thirty days prior to the valuation date. The expected term represents the period of time between the valuation date and the midpoint of the exercise window.
2020 Stock Appreciation Rights | |||||
Risk-free interest rate | 0.30 | % | |||
Dividend yield | — | % | |||
Volatility factor | 67.50 | % | |||
Expected term | 3.28 years | ||||
Number of Stock Appreciation Rights Granted | 1,240,000 | ||||
Weighted Average Grant Date Fair Value | $ | 2.61 | |||
Total Intrinsic Value of Exercises | $ | — |
As of December 31, 2021, $4.0 million of unrecognized compensation cost related to outstanding stock appreciation rights was expected to be recognized by December 31, 2022.
The following table summarizes stock appreciation rights activity as of December 31, 2021.
Stock Appreciation Rights | Shares | Weighted Average Exercise Price | Weighted Average Remaining Contractual Term | Aggregate Intrinsic Value | ||||||||||||||||||||||
Outstanding at January 1, 2021 | 1,240,000 | $ | 10.00 | |||||||||||||||||||||||
Granted | — | — | ||||||||||||||||||||||||
Outstanding at December 31, 2021 | 1,240,000 | 10.00 | 8.0 years | $ | 14,644,400 | |||||||||||||||||||||
Exercisable at December 31, 2021 | — | $ | — | — | $ | — |
Non-employee Directors' Share-Based Awards
Prior to 2020, the Company granted share-based awards that vested upon grant to non-employee directors. The share-based awards were historically paid in cash or EQT common stock following a directors' termination of service on the Company's Board of Directors. Beginning in 2020, the Company grants to non-employee directors restricted stock unit awards that vest on the date of the Company's annual meeting of shareholders immediately following the grant of such awards. The restricted stock unit awards are settled in EQT common stock on the vesting date or, if elected by the director, following a director's termination of service on the Company's Board of Directors.
Awards to be paid in cash are accounted for as liability awards and, as such, compensation expense is recorded based on the fair value of the awards as remeasured at the end of each reporting period. Awards to be settled in EQT common stock are accounted for as equity awards and, as such, compensation expense is recorded based on the fair value of the awards at the grant date fair value. A total of 430,858 non-employee director share-based awards, including accrued dividends, were outstanding as of December 31, 2021. A total of 120,080, 201,300 and 146,790 share-based awards were granted to non-employee directors during the years ended December 31, 2021, 2020 and 2019, respectively. The weighted average fair value of these grants, based on the closing EQT common stock price on the business day prior to the grant date, was $17.49, $13.46 and $18.11 for the years ended December 31, 2021, 2020 and 2019, respectively.
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2022 Awards
Effective in 2022, the Compensation Committee adopted the 2022 Incentive Performance Share Unit Program (2022 Incentive PSU Program) under the 2020 LTIP. The 2022 Incentive PSU Program was established to align the interests of executives and key employees with the interests of shareholders and the strategic objectives of the Company. A total of 575,120 share units were granted under the 2022 Incentive PSU Program. The payout of the share units will vary between zero and 200% of the number of outstanding units contingent upon a combination of the Company's absolute total shareholder return and total shareholder return relative to a predefined peer group over the period January 1, 2022 through December 31, 2024, modified based on the Company's performance in achieving its objective of net zero Scope 1 and Scope 2 greenhouse gas emissions by 2025.
Effective in 2022, the Compensation Committee granted 1,248,120 restricted stock unit equity awards that will follow a three-year graded vesting schedule commencing with the date of grant, assuming continued employment. The share total includes the instituted "equity-for-all" program, which granted equity awards to all permanent full-time employees beginning in 2021.
14. Concentrations of Credit Risk
Revenues and related accounts receivable from the Company's operations are generated primarily from the sale of produced natural gas, NGLs and oil to marketers, utilities and industrial customers located in the Appalachian Basin and in markets that are accessible through the Company's transportation portfolio, which includes markets in the Gulf Coast, Midwest and Northeast United States and Canada. The Company also contracts with certain processors to market a portion of NGLs on behalf of the Company. The Company does not depend on any single customer and believes that the loss of any one customer would not have an adverse effect on the Company's ability to sell its natural gas, NGLs and oil.
Approximately 90% and 86% of the Company's accounts receivable balances as of December 31, 2021 and 2020, respectively, represent amounts due from non-end users. The Company manages the credit risk of sales to non-end users by limiting its dealings with only non-end users that meet the Company's criteria for credit and liquidity strength and by regularly monitoring these accounts. The Company may require letters of credit, guarantees, performance bonds or other credit enhancements from a non-end user for that non-end user to meet the Company's credit criteria. The Company did not experience any significant defaults on sales of natural gas to non-end users during the years ended December 31, 2021, 2020 or 2019.
The Company is exposed to credit loss in the event of nonperformance by counterparties to its derivative contracts. This credit exposure is limited to derivative contracts with a positive fair value, which may change as market prices change. The Company's OTC derivative instruments are primarily with financial institutions and, thus, are subject to events that would impact those companies individually as well as the financial industry as a whole. The Company uses various processes and analyses to monitor and evaluate its credit risk exposures, including monitoring current market conditions and counterparty credit fundamentals. Credit exposure is controlled through credit approvals and limits based on counterparty credit fundamentals. To manage the level of credit risk, the Company enters into transactions primarily with financial counterparties that are of investment grade, enters into netting agreements whenever possible and may obtain collateral or other security.
As of December 31, 2021, the Company was not in default under any derivative contracts and had no knowledge of default by any counterparty to its derivative contracts. During the year ended December 31, 2021, the Company made no adjustments to the fair value of its derivative contracts due to credit related concerns outside of the normal non-performance risk adjustment included in the Company's established fair value procedure. The Company monitors market conditions that may impact the fair value of its derivative contracts.
15. Leases
The Company leases drilling rigs, facilities, vehicles and drilling and compression equipment.
On January 1, 2019, in connection with the Company's adoption of ASU 2016-02, Leases, the Company recorded in its Consolidated Balance Sheet $89.0 million of right-of-use assets and lease liabilities representing the present value of the Company's right to use its leased assets and obligation to make lease payments on those leased assets, respectively.
To determine the present value of its right-of-use assets and lease liabilities at adoption and thereafter, the Company calculates a discount rate per lease contract based on an estimate of the rate of interest that the Company would pay to borrow (on a collateralized basis, over a similar term) an amount equal to the lease payment obligation.
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Upon adoption of ASU 2016-02, the Company elected a practical expedient to forgo application of the recognition requirements under the standard to short-term leases; as such, short-term leases are not recorded in the Consolidated Balance Sheets. In addition, the Company elected a practical expedient to account for lease and nonlease components together as a lease.
Certain of the Company's lease contracts include variable lease payments, such as payments for property taxes and other operating and maintenance expenses and payments based on asset use, which are not included in the lease cost or the present value of the right-of-use asset or lease liability. Certain of the Company's lease contracts provide renewal periods at the Company's option; if a renewal period option is reasonably assured to be exercised, the associated lease payment obligation is included in the present value of the right-of-use asset and lease liability. As of December 31, 2021 and 2020, the Company was not a lessor.
The following table summarizes the Company's lease costs.
Years Ended December 31, | |||||||||||||||||
2021 | 2020 | 2019 | |||||||||||||||
(Thousands) | |||||||||||||||||
Operating and finance lease costs | $ | 19,826 | $ | 28,286 | $ | 57,517 | |||||||||||
Variable and short-term lease costs | 11,516 | 15,922 | 17,143 | ||||||||||||||
Total lease costs (a) | $ | 31,342 | $ | 44,208 | $ | 74,660 |
(a)Includes drilling rig lease costs capitalized to property, plant and equipment of $22.1 million, $29.9 million and $58.5 million, respectively, of which $16.5 million, $19.9 million and $48.1 million, respectively, were operating lease costs.
For the years ended December 31, 2021, 2020 and 2019, cash paid for lease liabilities and reported in cash flows provided by operating activities in the Statements of Consolidated Cash Flows was $9.7 million, $10.4 million and $10.8 million, respectively. For the year ended December 31, 2021, cash paid for lease liabilities and reported in cash flows provided by financing activities in the Statements of Consolidated Cash Flows was $1.1 million. During the years ended December 31, 2021, 2020 and 2019, the Company recorded $20.8 million, $18.9 million and $24.3 million, respectively, of right-of-use assets in exchange for new lease liabilities. As of December 31, 2021, 2020 and 2019, the weighted average remaining lease term was 2.6 years, 2.8 years and 3.3 years, respectively. For the years ended December 31, 2021, 2020 and 2019, the weighted average discount rate was 2.9%, 3.3% and 3.3%, respectively.
The Company records its right-of-use assets in other assets and the current and noncurrent portions of its lease liabilities in other current liabilities and other liabilities and credits, respectively, in the Consolidated Balance Sheets. As of December 31, 2021 and 2020, total right-of-use assets were $26.1 million and $21.6 million, respectively, and total lease liabilities were $52.7 million and $49.9 million, respectively, of which $28.0 million and $25.0 million, respectively, were classified as current.
During the fourth quarter of 2020, the Company recognized $22.8 million of right-of-use asset impairment in impairment of intangible and other assets in the Statement of Consolidated Operations as a result of the Company's assessment that the fair values of certain of the Company's right-of-use assets were less than their carrying values.
The following table summarizes the Company's lease payment obligations as of December 31, 2021.
December 31, 2021 | |||||
(Thousands) | |||||
2022 | $ | 29,075 | |||
2023 | 14,440 | ||||
2024 | 7,862 | ||||
2025 | 1,091 | ||||
2026 | 813 | ||||
Thereafter | 1,715 | ||||
Total lease payment obligations | 54,996 | ||||
Less: Interest | 2,284 | ||||
Present value of lease liabilities | $ | 52,712 |
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16. Commitments and Contingencies
The Company has commitments for demand charges under existing long-term contracts and binding precedent agreements with various pipelines as well as commitments for processing capacity. 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.
In addition, the Company has commitments to pay for services and materials related to its operations, which primarily include minimum volume commitments to obtain water services and electric hydraulic fracturing services and commitments to purchase equipment, materials and sand. As of December 31, 2021, future commitments under these contracts were $135.6 million in 2022, $99.0 million in 2023, $47.5 million in 2024, $40.0 million in 2025, $40.0 million in 2026 and $178.3 million thereafter.
See Note 15 for a summary of undiscounted future cash flows owed by the Company as lessee to lessors pursuant to contractual agreements in effect as of December 31, 2021.
Conditioned upon the credit ratings assigned by Moody's, S&P and Fitch to the Company's senior notes, counterparties to the Company's derivative and midstream services contracts may request additional assurances of the Company, including collateral. See Note 3 for a description of what is deemed investment grade and a discussion of other factors, aside from credit ratings, that may affect margin deposit requirements on the Company's derivative contracts. See Note 10 for a discussion of letters of credit outstanding and surety bonds posted as of December 31, 2021.
In the ordinary course of business, various legal and regulatory claims and proceedings are pending or threatened against the Company. While the amounts claimed may be substantial, the Company is unable to predict with certainty the ultimate outcome of such claims and proceedings. The Company accrues legal and other direct costs related to loss contingencies when actually incurred. The Company has established reserves it believes to be appropriate for pending matters and, after consultation with counsel and giving appropriate consideration to available insurance, the Company believes that the ultimate outcome of any matter currently pending against the Company will not materially affect the financial position, results of operations or liquidity of the Company.
The Company is subject to various federal, state and local environmental and environmentally-related laws and regulations. These laws and regulations, which are constantly changing, can require expenditures for remediation and may result in the assessment of fines. The Company has established procedures for ongoing evaluation of its operations to identify potential environmental exposures and to assure compliance with regulatory policies and procedures. The estimated costs associated with identified situations that require remedial action are accrued. Ongoing expenditures for compliance with environmental laws and regulations, including investments in plant and facilities to meet environmental requirements, have not been material. Management believes that any such required expenditures will not be significantly different in either their nature or amount in the future and does not know of any environmental liabilities that will have a material effect on the Company's financial position, results of operations or liquidity. The Company has identified situations that require remedial action for which approximately $8.3 million was recorded in other liabilities and credits in the Consolidated Balance Sheet as of December 31, 2021.
17. Guarantees
In connection with the sale of its NORESCO domestic operations in 2005, the Company agreed to maintain in-place guarantees of certain warranty obligations of NORESCO. The savings guarantees provided that, once an energy-efficiency construction project was completed by NORESCO, the customer would experience a certain dollar amount of energy savings over a number of years. The undiscounted maximum aggregate payments that may be due related to these guarantees were approximately $30 million as of December 31, 2021, extending at a decreasing amount for approximately 7 years.
This guarantee is exempt from ASC Topic 460, Guarantees. The Company considers the likelihood that it will be required to perform on these arrangements to be remote and expects any potential payments to be immaterial to the Company's financial position, results of operations and liquidity. As such, the Company has not recorded any liabilities related to this guarantee in its Consolidated Balance Sheets.
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18. Natural Gas Producing Activities (Unaudited)
The following supplementary information summarized presents the results of natural gas and oil activities in accordance with the successful efforts method of accounting for production activities.
Production Costs
The following tables present total aggregate capitalized costs and costs incurred related to natural gas, NGLs and oil production activities.
December 31, | |||||||||||||||||
2021 | 2020 | ||||||||||||||||
(Thousands) | |||||||||||||||||
Capitalized costs | |||||||||||||||||
Proved properties | $ | 23,117,987 | $ | 19,479,211 | |||||||||||||
Unproved properties | 2,405,867 | 2,291,814 | |||||||||||||||
Total capitalized costs | 25,523,854 | 21,771,025 | |||||||||||||||
Less: Accumulated depreciation and depletion | 7,508,178 | 5,866,418 | |||||||||||||||
Net capitalized costs | $ | 18,015,676 | $ | 15,904,607 |
Years Ended December 31, | |||||||||||||||||
2021 | 2020 | 2019 | |||||||||||||||
(Thousands) | |||||||||||||||||
Costs incurred (a) | |||||||||||||||||
Property acquisition: | |||||||||||||||||
Proved properties (b) | $ | 2,286,386 | $ | 761,940 | $ | 40,316 | |||||||||||
Unproved properties (c) | 805,942 | 78,404 | 154,128 | ||||||||||||||
Exploration | 24,403 | 5,484 | 7,223 | ||||||||||||||
Development | 950,531 | 947,233 | 1,560,346 | ||||||||||||||
(a)Amounts exclude capital expenditures for facilities, information technology and other corporate items as well as the acquired midstream assets described in Note 6.
(b)Amounts in 2021 include $1,754.7 million and $450.0 million for Marcellus wells and leases, respectively, acquired in the Alta Acquisition and Reliance Asset Acquisition described in Note 6. Amounts in 2020 include $674.0 million and $6.5 million for Marcellus and Utica wells, respectively, acquired in the Chevron Acquisition.
(c)Amounts in 2021 include $743.3 million for unproved properties acquired in the Alta Acquisition. Amounts in 2020 include $38.9 million for unproved properties acquired in the Chevron Acquisition.
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Results of Operations for Producing Activities
The following table presents the results of operations related to natural gas, NGLs and oil production.
Years Ended December 31, | |||||||||||||||||
2021 | 2020 | 2019 | |||||||||||||||
(Thousands) | |||||||||||||||||
Sales of natural gas, NGLs and oil | $ | 6,804,020 | $ | 2,650,299 | $ | 3,791,414 | |||||||||||
Transportation and processing | 1,942,165 | 1,710,734 | 1,752,752 | ||||||||||||||
Production | 225,279 | 155,403 | 153,785 | ||||||||||||||
Exploration | 24,403 | 5,484 | 7,223 | ||||||||||||||
Depreciation and depletion | 1,676,702 | 1,393,465 | 1,538,745 | ||||||||||||||
(Gain) loss/impairment on sale/exchange of long-lived assets | (21,124) | 100,729 | 1,138,287 | ||||||||||||||
Impairment and expiration of leases | 311,835 | 306,688 | 556,424 | ||||||||||||||
Income tax expense (benefit) | 667,435 | (254,671) | (340,843) | ||||||||||||||
Results of operations from producing activities, excluding corporate overhead | $ | 1,977,325 | $ | (767,533) | $ | (1,014,959) |
Reserve Information
Proved developed reserves represent only those reserves expected to be recovered from existing wells and support equipment. Proved undeveloped reserves represent proved reserves expected to be recovered from new wells after substantial development costs are incurred.
The Company's estimate of proved natural gas, NGLs and crude oil reserves was prepared by Company engineers. The engineer primarily responsible for overseeing the preparation of the reserves estimate holds a bachelor's degree in chemical engineering from Michigan Technological University, a master's degree in chemical engineering from Colorado State University and an executive master of business administration in energy from the University of Oklahoma and has 21 years of experience in the oil and gas industry. To support the accurate and timely preparation and disclosure of its reserve estimates, the Company established internal controls over its reserve estimation processes and procedures, including the following: the price, heat content conversion rate and cost assumptions used in the economic model to determine the reserves are reviewed by management; division of interest and production volume are reconciled between the system used to calculate the reserves and other accounting/measurement systems; the reserves reconciliation between prior year reserves and current year reserves is reviewed by senior management; and the estimates of proved natural gas, NGLs and crude oil reserves are audited by Netherland, Sewell & Associates, Inc. (NSAI), an independent consulting firm hired by management. Since 1961, NSAI has evaluated oil and gas properties and independently certified petroleum reserves quantities in the United States and internationally.
In the course of its audit, NSAI conducted a detailed review of 100% of the total net natural gas, NGLs and oil proved reserves attributable to the Company's interests as of December 31, 2021. NSAI conducted a detailed, well-by-well audit of all the Company's properties. The estimates prepared by the Company and audited by NSAI were within the recommended 10% tolerance threshold set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). Standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, analogy and material balance were utilized in the evaluation of reserves. All of the Company's proved reserves are located in the United States.
During 2020, the Company conducted a study of its reserves areas to determine the reliability of the technology used in calculating the Company's reserves. This study demonstrated that technologies used in the course of the Company's reserves determination are reliable, provide reasonable certainty of future performance and economics of the Company's wells, and conform to booking practices when using reliable technologies. The technologies used in the estimation of the Company's proved reserves include, but are not limited to, empirical evidence through drilling results and well performance, production data, decline curve analysis, well logs, geologic maps, core data, seismic data, demonstrated relationship between geologic parameters and performance, and the implementation and application of statistical analysis.
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For all tables presented, NGLs and oil were converted at a rate of one Mbbl to approximately six million cubic feet (MMcf).
Years Ended December 31, | |||||||||||||||||
2021 | 2020 | 2019 | |||||||||||||||
(MMcf) | |||||||||||||||||
Natural gas, NGLs and oil | |||||||||||||||||
Proved developed and undeveloped reserves: | |||||||||||||||||
Balance at January 1 | 19,802,092 | 17,469,394 | 21,816,776 | ||||||||||||||
Revision of previous estimates | (274,111) | (739,213) | (4,907,239) | ||||||||||||||
Purchase of hydrocarbons in place | 4,186,933 | 1,380,564 | — | ||||||||||||||
Sale of hydrocarbons in place | — | (256,663) | — | ||||||||||||||
Extensions, discoveries and other additions | 3,104,402 | 3,445,802 | 2,067,753 | ||||||||||||||
Production | (1,857,817) | (1,497,792) | (1,507,896) | ||||||||||||||
Balance at December 31 | 24,961,499 | 19,802,092 | 17,469,394 | ||||||||||||||
Proved developed reserves: | |||||||||||||||||
Balance at January 1 | 13,641,345 | 12,443,987 | 11,550,161 | ||||||||||||||
Balance at December 31 | 17,218,655 | 13,641,345 | 12,443,987 | ||||||||||||||
Proved undeveloped reserves: | |||||||||||||||||
Balance at January 1 | 6,160,747 | 5,025,407 | 10,266,615 | ||||||||||||||
Balance at December 31 | 7,742,844 | 6,160,747 | 5,025,407 |
Years Ended December 31, | |||||||||||||||||
2021 | 2020 | 2019 | |||||||||||||||
(MMcf) | |||||||||||||||||
Natural gas | |||||||||||||||||
Proved developed and undeveloped reserves: | |||||||||||||||||
Balance at January 1 | 18,865,013 | 16,677,202 | 20,805,452 | ||||||||||||||
Revision of previous estimates | (568,814) | (781,668) | (4,722,799) | ||||||||||||||
Purchase of natural gas in place | 4,186,933 | 1,209,326 | — | ||||||||||||||
Sale of natural gas in place | — | (254,930) | — | ||||||||||||||
Extensions, discoveries and other additions | 2,786,850 | 3,433,857 | 2,029,683 | ||||||||||||||
Production | (1,746,317) | (1,418,774) | (1,435,134) | ||||||||||||||
Balance at December 31 | 23,523,665 | 18,865,013 | 16,677,202 | ||||||||||||||
Proved developed reserves: | |||||||||||||||||
Balance at January 1 | 12,750,312 | 11,811,521 | 10,887,953 | ||||||||||||||
Balance at December 31 | 16,152,083 | 12,750,312 | 11,811,521 | ||||||||||||||
Proved undeveloped reserves: | |||||||||||||||||
Balance at January 1 | 6,114,701 | 4,865,681 | 9,917,499 | ||||||||||||||
Balance at December 31 | 7,371,582 | 6,114,701 | 4,865,681 |
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Years Ended December 31, | |||||||||||||||||
2021 | 2020 | 2019 | |||||||||||||||
(Mbbl) | |||||||||||||||||
NGLs | |||||||||||||||||
Proved developed and undeveloped reserves: | |||||||||||||||||
Balance at January 1 | 148,762 | 126,955 | 162,395 | ||||||||||||||
Revision of previous estimates | 46,868 | 6,825 | (30,312) | ||||||||||||||
Purchase of NGLs in place | — | 25,879 | — | ||||||||||||||
Sale of NGLs in place | — | (289) | — | ||||||||||||||
Extensions, discoveries and other additions | 47,120 | 1,757 | 6,177 | ||||||||||||||
Production | (16,958) | (12,365) | (11,305) | ||||||||||||||
Balance at December 31 | 225,792 | 148,762 | 126,955 | ||||||||||||||
Proved developed reserves: | |||||||||||||||||
Balance at January 1 | 141,489 | 100,945 | 106,879 | ||||||||||||||
Balance at December 31 | 169,781 | 141,489 | 100,945 | ||||||||||||||
Proved undeveloped reserves: | |||||||||||||||||
Balance at January 1 | 7,273 | 26,010 | 55,516 | ||||||||||||||
Balance at December 31 | 56,011 | 7,273 | 26,010 |
Years Ended December 31, | |||||||||||||||||
2021 | 2020 | 2019 | |||||||||||||||
(Mbbl) | |||||||||||||||||
Oil | |||||||||||||||||
Proved developed and undeveloped reserves: | |||||||||||||||||
Balance at January 1 | 7,417 | 5,077 | 6,159 | ||||||||||||||
Revision of previous estimates | 2,249 | 250 | (428) | ||||||||||||||
Purchase of oil in place | — | 2,660 | — | ||||||||||||||
Sale of oil in place | — | — | — | ||||||||||||||
Extensions, discoveries and other additions | 5,805 | 234 | 168 | ||||||||||||||
Production | (1,625) | (804) | (822) | ||||||||||||||
Balance at December 31 | 13,846 | 7,417 | 5,077 | ||||||||||||||
Proved developed reserves: | |||||||||||||||||
Balance at January 1 | 7,016 | 4,466 | 3,489 | ||||||||||||||
Balance at December 31 | 7,981 | 7,016 | 4,466 | ||||||||||||||
Proved undeveloped reserves: | |||||||||||||||||
Balance at January 1 | 401 | 611 | 2,670 | ||||||||||||||
Balance at December 31 | 5,865 | 401 | 611 |
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The change in reserves during the year ended December 31, 2021 resulted from the following:
•Conversions of 1,634 Bcfe of proved undeveloped reserves to proved developed reserves.
•Extensions, discoveries and other additions of 3,104 Bcfe, which exceeded 2021 production of 1,858 Bcfe. Extensions, discoveries and other additions included an increase of 2,828 Bcfe of proved undeveloped additions associated with acreage that was previously unproved but became proved due to 2021 reserve development that expanded the number of the Company's proven locations, implementation of, and alignment with, the Company's combo-development strategy and additions to the Company's five-year drilling plan, 52 Bcfe from extension of proved undeveloped reserves lateral lengths and 224 Bcfe from converting unproved reserves to proved developed reserves.
•Negative revisions of 819 Bcfe from proved undeveloped locations that are no longer expected to be developed within five years of initial booking as proved reserves as a result of revisions to the Company’s five-year drilling plan allowing for continued alignment with the Company’s combo-development strategy.
•Negative revisions to proved undeveloped locations of 62 Bcfe due primarily to changes in working interests and net revenue interest.
•Negative revisions of 31 Bcfe primarily from proved developed locations as a result of negative curve revisions.
•Positive revisions of 638 Bcfe from higher pricing that impacted well economics.
•Purchase of hydrocarbons in place of 4,187 Bcfe from the Alta Acquisition and Reliance Asset Acquisition described in Note 6.
The change in reserves during the year ended December 31, 2020 resulted from the following:
•Conversions of 2,102 Bcfe of proved undeveloped reserves to proved developed reserves.
•Extensions, discoveries and other additions of 3,446 Bcfe, which exceeded 2020 production of 1,498 Bcfe. Extensions, discoveries and other additions included an increase of 2,096 Bcfe of proved undeveloped additions associated with acreage that was previously unproved but became proved using reliable technologies which expanded the number of the Company's technically proven locations, 1,295 Bcfe due to additions associated with directly offsetting development, 31 Bcfe from extension of proved undeveloped reserves lateral lengths and 24 Bcfe from converting unproved reserves to proved developed reserves.
•Negative revisions of 510 Bcfe from proved undeveloped locations that are no longer expected to be developed within five years of initial booking as proved reserves as a result of revisions to the Company’s five-year drilling plan allowing for continued alignment with the Company’s combo-development strategy. This includes 245 Bcfe from lower pricing that impacted well economics, shifting capital from the Ohio Utica, to Pennsylvania and West Virginia Marcellus, and 265 Bcfe as a result of continued implementation of the Company's combo-development strategy.
•Negative revisions of 384 Bcfe primarily from proved developed locations as a result of negative curve revisions in the Ohio Utica.
•Positive revisions to proved undeveloped locations of 155 Bcfe due primarily to changes in working interests and net revenue interests as well as type curve updates.
•Purchase of hydrocarbons in place of 1,381 Bcfe from the Chevron Acquisition described in Note 6.
•Sale of hydrocarbons in place of 257 Bcfe due to the 2020 Divestiture described in Note 8.
The change in reserves during the year ended December 31, 2019 resulted from the following:
•Conversions of 2,646 Bcfe of proved undeveloped reserves to proved developed reserves.
•Extensions, discoveries and other additions of 2,068 Bcfe, which exceeded 2019 production of 1,508 Bcfe. Extensions, discoveries and other additions included an increase of 1,796 Bcfe from proved undeveloped additions associated with acreage that was previously unproved, but became proved due to 2019 reserve development that expanded the number of the Company's technically proven locations, implementation of, and alignment with, the Company's combo-development strategy and revisions to the Company's five-year drilling plan; 156 Bcfe from converting unproved reserves to proved developed reserves; and 116 Bcfe from extension of proved undeveloped reserves lateral lengths.
•Negative revisions of 4,508 Bcfe from proved undeveloped locations that are no longer expected to be developed within five years of initial booking as proved reserves as a result of implementation of the Company's combo-development strategy, which has refocused operations in the Company's core assets and driven execution of new development sequencing processes that emphasize productivity. While these efforts are expected to result in decreased well costs, they negatively impact proved undeveloped reserves as a result of (i) derecognizing previously-recorded proved undeveloped reserves that are now outside the Company's substantially revised five-year capital allocation program for purposes of the Company's reserves calculations and (ii) executing new development sequencing processes that will result in increased probable-to-proved developed conversion.
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Standard Measure of Discounted Future Cash Flow
Management cautions that the standard measure of discounted future cash flows should not be viewed as an indication of the fair market value of natural gas and oil producing properties, nor of the future cash flows expected to be generated therefrom. The information presented does not give recognition to future changes in estimated reserves, selling prices or costs and has been discounted at a rate of 10%.
The following table summarizes estimated future net cash flows from natural gas and crude oil reserves.
December 31, | |||||||||||||||||
2021 | 2020 | 2019 | |||||||||||||||
(Thousands) | |||||||||||||||||
Future cash inflows (a) | $ | 70,844,136 | $ | 27,976,557 | $ | 42,499,686 | |||||||||||
Future production costs (b) | (20,961,576) | (16,344,965) | (19,114,076) | ||||||||||||||
Future development costs | (2,882,921) | (2,268,109) | (2,617,731) | ||||||||||||||
Future income tax expenses | (10,433,091) | (1,820,341) | (3,013,667) | ||||||||||||||
Future net cash flow | 36,566,548 | 7,543,142 | 17,754,212 | ||||||||||||||
10% annual discount for estimated timing of cash flows | (19,285,424) | (4,176,684) | (9,261,539) | ||||||||||||||
Standardized measure of discounted future net cash flows | $ | 17,281,124 | $ | 3,366,458 | $ | 8,492,673 |
(a)The majority of the Company's production is sold through liquid trading points on interstate pipelines.
For 2021, reserves were computed using average first-day-of-the-month closing prices for the prior twelve months of $66.55 per Bbl for West Texas Intermediate (WTI) less regional adjustments of $14.98 per Bbl, or $51.57 per Bbl, and $3.598 per MMBtu for NYMEX less regional adjustments of $1.04 per MMBtu, or $2.694 per Mcf. Regional adjustments were calculated using historical average realized prices received in the Appalachian Basin. For 2021, NGLs pricing using average first-day-of-the-month closing prices for the prior twelve months for NGLs components, adjusted using the regional component makeup of proved NGLs, resulted in a price of $29.95 per Bbl.
For 2020, reserves were computed using average first-day-of-the-month closing prices for the prior twelve months of $39.54 per Bbl for WTI less regional adjustments of $18.60 per Bbl, or $20.94 per Bbl, and $1.985 per MMBtu for NYMEX less regional adjustments of $0.68 per MMBtu, or $1.38 per Mcf. Regional adjustments were calculated using historical average realized prices received by the Company in the Appalachian Basin. For 2020, NGLs pricing using average first-day-of-the-month closing prices for the prior twelve months for NGLs components, adjusted using the regional component makeup of proved NGLs, resulted in a price of $11.97 per Bbl.
For 2019, reserves were computed using average first-day-of-the-month closing prices for the prior twelve months of $55.69 per Bbl for WTI less regional adjustments of $14.26 per Bbl, or $41.43 per Bbl, and $2.58 per MMBtu for NYMEX less regional adjustments of $0.29 per MMBtu, or $2.41 per Mcf. Regional adjustments were calculated using historical average realized prices received by the Company in the Appalachian Basin. For 2019, NGLs pricing using average first-day-of-the-month closing prices for the prior twelve months for NGLs components, adjusted using the regional component makeup of proved NGLs, resulted in a price of $16.81 per Bbl.
(b)Includes approximately $1,937 million, $1,554 million and $1,186 million for future plugging and abandonment costs as of December 31, 2021, 2020 and 2019, respectively.
Holding production and development costs constant, an increase in NYMEX price of $0.10 per Dth for natural gas, an increase in WTI of $10 per barrel for NGLs and an increase in WTI of $10 per barrel for oil would result in a change in the December 31, 2021 discounted future net cash flows before income taxes of the Company's proved reserves of approximately $1,125 million, $430 million and $76 million, respectively.
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The following table summarizes the changes in the standardized measure of discounted future net cash flows.
Years Ended December 31, | |||||||||||||||||
2021 | 2020 | 2019 | |||||||||||||||
(Thousands) | |||||||||||||||||
Net sales and transfers of natural gas and oil produced | $ | (4,636,576) | $ | (784,163) | $ | (1,884,877) | |||||||||||
Net changes in prices, production and development costs | 17,290,913 | (6,761,447) | (3,502,434) | ||||||||||||||
Extensions, discoveries and improved recovery, net of related costs | 46,078 | 714,808 | 870,504 | ||||||||||||||
Development costs incurred | 764,002 | 797,796 | 1,002,389 | ||||||||||||||
Net purchase of minerals in place | 3,491,441 | 350,075 | — | ||||||||||||||
Net sale of minerals in place | — | (226,497) | — | ||||||||||||||
Revisions of previous quantity estimates | 184,552 | (324,415) | (2,080,040) | ||||||||||||||
Accretion of discount | 336,646 | 849,267 | 900,004 | ||||||||||||||
Net change in income taxes | (3,614,029) | 152,978 | 1,444,368 | ||||||||||||||
Timing and other | 51,639 | 105,383 | 130,861 | ||||||||||||||
Net increase (decrease) | 13,914,666 | (5,126,215) | (3,119,225) | ||||||||||||||
Balance at January 1 | 3,366,458 | 8,492,673 | 11,611,898 | ||||||||||||||
Balance at December 31 | $ | 17,281,124 | $ | 3,366,458 | $ | 8,492,673 |
66
EQT CORPORATION AND SUBSIDIARIES
SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE THREE YEARS ENDED DECEMBER 31, 2021
Column A | Column B | Column C | Column D | Column E | ||||||||||||||||||||||||||||
Description | Balance at Beginning of Period | (Deductions) Additions Charged to Costs and Expenses | Additions Charged to Other Accounts | Deductions | Balance at End of Period | |||||||||||||||||||||||||||
(Thousands) | ||||||||||||||||||||||||||||||||
Valuation allowance for deferred tax assets: | ||||||||||||||||||||||||||||||||
2021 | $ | 529,992 | $ | 38,556 | $ | — | $ | (17,581) | $ | 550,967 | ||||||||||||||||||||||
2020 | $ | 423,444 | $ | 132,386 | $ | — | $ | (25,838) | $ | 529,992 | ||||||||||||||||||||||
2019 | $ | 351,408 | $ | 84,260 | $ | 1,114 | $ | (13,338) | $ | 423,444 |
All other schedules are omitted since the subject matter thereof is either not present or is not present in amounts sufficient to require submission of the schedules.
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