EQT CORPORATION 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 for 2020 was$967 million ,$3.71 per diluted share, an improvement of$255 million compared to net loss for 2019 of$1,222 million ,$4.79 per diluted share. The variance was attributable primarily to decreased impairments, the gain on the Equitrans Share Exchange (defined and discussed in Note 5 to the Consolidated Financial Statements), decreased other operating expenses, decreased depreciation and depletion expense and decreased transportation and processing expense, partly offset by decreased operating revenues, increased interest expense and decreased dividend and other income. See Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations" included in our Annual Report on Form 10-K for the year endedDecember 31, 2019 , which is incorporated herein by reference, for discussion and analysis of consolidated results of operations for the year endedDecember 31, 2018 . See "Sales Volumes and Revenues" and "Operating Expenses" for discussions of items affecting operating income and "Other Income Statement Items" for a discussion of other income statement items. See "Investing Activities" under "Capital Resources and Liquidity" for a discussion of capital expenditures.
Average Realized Price Reconciliation
The following table presents detailed natural gas and liquids operational
information to assist in the understanding of our consolidated operations,
including the calculation of our average realized price ($/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,
2020 2019
(Thousands, unless otherwise noted)
NATURAL GAS
Sales volume (MMcf) 1,418,774 1,435,134
NYMEX price ($/MMBtu) (a) $ 2.09 $ 2.63
Btu uplift 0.11 0.13
Natural gas price ($/Mcf) $ 2.20 $ 2.76
Basis ($/Mcf) (b) $
(0.47)
0.05 (0.04)
Average differential, including cash settled basis swaps ($/Mcf)
$
(0.42)
Average adjusted price ($/Mcf) $
1.78
0.59 0.21
Average natural gas price, including cash settled
derivatives ($/Mcf) $
2.37
Natural gas sales, including cash settled derivatives $ 3,359,583
LIQUIDS
Natural gas liquids (NGLs), excluding ethane: Sales volume (MMcfe) (c) 44,702 44,082 Sales volume (Mbbl) 7,451 7,348 Price ($/Bbl) $
20.51
(0.12) 2.19
Average NGLs price, including cash settled derivatives
($/Bbl) $ 20.39 $ 25.82
NGLs sales $ 151,877 $ 189,718
Ethane:
Sales volume (MMcfe) (c) 29,489 23,748
Sales volume (Mbbl) 4,914 3,957
Price ($/Bbl) $
3.48
- 1.02
Average Ethane price, including cash settled derivatives
($/Bbl) $ 3.48 $ 7.18
Ethane sales $ 17,085 $ 28,414
Oil:
Sales volume (MMcfe) (c) 4,827 4,932
Sales volume (Mbbl) 804 822
Price ($/Bbl) $ 25.57 $ 40.90
Oil sales $ 20,574 $ 33,620
Total liquids sales volume (MMcfe) (c) 79,018 72,762
Total liquids sales volume (Mbbl) 13,169 12,127
Total liquids sales $
189,536
TOTAL
Total natural gas and liquids sales, including cash settled derivatives (d)
$ 3,549,119 $ 4,057,729
Total sales volume (MMcfe) 1,497,792 1,507,896
Average realized price ($/Mcfe) $
2.37
(a)Our volume weighted NYMEX natural gas price (actual average NYMEX natural gas price ($/MMBtu)) was$2.08 and$2.63 for the years endedDecember 31, 2020 and 2019, respectively. (b)Basis represents the difference between the ultimate sales price for natural gas and the NYMEX natural gas price. (c)NGLs, ethane and oil were converted to Mcfe at a rate of six Mcfe per barrel. (d)Total natural gas and liquids sales, including cash settled derivatives, is also referred to in this report as adjusted operating revenues, a non-GAAP supplemental financial measure. 46 -------------------------------------------------------------------------------- Table of Contents 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 primarily includes the costs of, and recoveries on, pipeline capacity releases. 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, 2020 2019 (Thousands, unless otherwise noted) Total operating revenues $ 3,058,843$ 4,416,484 Add (deduct): Gain on derivatives not designated as hedges (400,214) (616,634) Net cash settlements received on derivatives not designated as hedges 897,190 246,639
Premiums received for derivatives that settled during the period
1,630 19,676
Net marketing services and other (8,330) (8,436)
Adjusted operating revenues, a non-GAAP financial
measure $
3,549,119
Total sales volumes (MMcfe) 1,497,792 1,507,896 Average realized price ($/Mcfe) $
2.37 $ 2.69
Sales Volumes and Revenues
Years Ended December 31,
2020 2019 %
(Thousands, unless otherwise noted)
Sales volume by shale (MMcfe):
Marcellus (a) 1,314,801 1,270,352 3.5
Ohio Utica 177,864 231,545 (23.2)
Other 5,127 5,999 (14.5)
Total sales volumes (b) 1,497,792 1,507,896 (0.7)
Average daily sales volumes (MMcfe/d) 4,092 4,131 (0.9)
Operating revenues:
Sales of natural gas, NGLs and oil $ 2,650,299 $ 3,791,414 (30.1)
Gain on derivatives not designated as hedges 400,214 616,634 (35.1)
Net marketing services and other 8,330 8,436 (1.3)
Total operating revenues $ 3,058,843 $ 4,416,484 (30.7)
(a)Includes Upper Devonian wells. (b)NGLs, ethane and oil were converted to Mcfe at a rate of six Mcfe per barrel.
Sales of natural gas, NGLs and oil. Sales of natural gas, NGLs and oil decreased for 2020 compared to 2019 due to a lower average realized price and lower sales volumes. Average realized price decreased due to lower NYMEX and unfavorable differential, partly offset by higher cash settled derivatives. For 2020 and 2019, we received$898.8 million and$266.3 million , respectively, of net cash settlements, including net premiums received, on derivatives not designated as hedges, which are included in average realized price but may not be included in operating revenues. Sales volumes for 2020 decreased compared 47 -------------------------------------------------------------------------------- Table of Contents to 2019 due primarily to our strategic decisions to temporarily curtail production beginning inMay 2020 and ending inNovember 2020 (the Strategic Production Curtailments) which resulted in a decrease to sales volumes of approximately 46 Bcfe. Sales volumes for 2020 also decreased compared to 2019 by 16 Bcfe as a result of the 2020 Divestitures (defined in Note 7 to the Consolidated Financial Statements). These decreases were partly offset by operational efficiencies realized throughout the year from increased production up-time and positively impacted sales volumes as well as an increase of approximately 12 Bcfe due to the Chevron Acquisition.
Gain on derivatives not designated as hedges. For 2020, we recognized a gain on
derivatives not designated as hedges of
Operating Expenses
The following table presents information on our production-related operating
expenses.
Years Ended December 31,
2020 2019 %
(Thousands, unless otherwise noted)
Operating expenses:
Gathering $ 1,068,590 $ 1,038,646 2.9
Transmission 506,668 588,302 (13.9)
Processing 135,476 125,804 7.7
Lease operating expenses (LOE), excluding production
taxes 109,027 84,501 29.0
Production taxes 46,376 69,284 (33.1)
Exploration 5,484 7,223 (24.1)
Selling, general and administrative 174,769 170,611 2.4
Production depletion $ 1,375,542 $ 1,524,112 (9.7)
Other depreciation and depletion 17,923 14,633 22.5
Total depreciation and depletion $ 1,393,465 $ 1,538,745 (9.4)
Per Unit ($/Mcfe):
Gathering $ 0.71 $ 0.69 2.9
Transmission 0.34 0.39 (12.8)
Processing 0.09 0.08 12.5
LOE, excluding production taxes 0.07 0.06 16.7
Production taxes 0.03 0.05 (40.0)
Exploration - - -
Selling, general and administrative 0.12 0.11 9.1
Production depletion 0.92 1.01 (8.9)
Gathering. Gathering expense increased on an absolute and per Mcfe basis for
2020 compared to 2019 due to a higher gathering rate structure as a result of
the Consolidated GGA (defined in Note 5 to the Consolidated Financial
Statements), partly offset by lower gathered volumes as a result of the
Strategic Production Curtailments. We expect to realize fee relief and a lower
gathering rate structure from the Consolidated GGA beginning on the Mountain
Valley Pipeline in-service date.
Transmission. Transmission expense decreased on an absolute and per Mcfe basis
for 2020 compared to 2019 due primarily to released capacity on, and credits
received from, the Texas Eastern Transmission Pipeline, partly offset by higher
costs associated with additional capacity on the Tennessee Gas Pipeline .
LOE. LOE increased on an absolute and per Mcfe basis for 2020 compared to 2019
due primarily to higher repairs and maintenance costs as a result of our
increased focus on optimizing production from currently producing wells as well
as higher salt water disposal costs.
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Production taxes. Production taxes decreased on an absolute and per Mcfe basis
for 2020 compared to 2019 due primarily to lower severance taxes and
Pennsylvania impact fees as a result of lower commodity prices.
Depreciation and depletion. Production depletion decreased on an absolute and per Mcfe basis for 2020 compared to 2019 due primarily to a lower annual depletion rate and lower volumes.
Amortization of intangible assets. Amortization of intangible assets for 2020 was$26.0 million compared to$35.9 million for 2019. The decrease was due primarily to the impairment of intangible assets recognized in the third quarter of 2019 as described below, which decreased the amortization rate. The intangible assets were fully amortized inNovember 2020 . Impairment/loss on sale/exchange of long-lived assets. During 2020, we recognized a loss on sale/exchange of long-lived assets of$100.7 million , of which$61.6 million related to the 2020 Asset Exchange Transactions (defined and discussed in Note 6 to the Consolidated Financial Statements) and$39.1 million related to asset sales (described in Note 7 to the Consolidated Financial Statements). During the fourth quarter of 2019, we recorded impairment of long-lived assets of$1,124.4 million , of which$1,035.7 million was associated with our non-strategic assets located in the Ohio Utica and$88.7 million was associated with ourPennsylvania and West Virginia Utica assets. The impairment was due primarily to depressed natural gas prices and changes in our development strategy. During the third quarter of 2019, we recorded a loss on exchange of long-lived assets of$13.9 million related to the 2019 Asset Exchange Transaction (defined and discussed in Note 6 to the Consolidated Financial Statements). See Note 1 to the Consolidated Financial Statements for a discussion of the 2019 impairment test. Impairment of intangible and other assets. During the fourth quarter of 2020, we recognized impairment of$34.7 million , of which$22.8 million related to our assessment that the fair values of certain of our right-of-use lease assets were less than their carrying values and$11.9 million related to impairments of certain non-operating receivables as a result of expected credit losses. During the third quarter of 2019, we recognized impairment of$15.4 million of intangible assets associated with non-compete agreements for former Rice Energy Inc. executives who are now our employees. Impairment and expiration of leases. Impairment and expiration of leases for 2020 was$306.7 million compared to$556.4 million for 2019. The decrease was driven by increased lease expirations in 2019 due to our change in strategic focus to core development opportunities as well as changes in market conditions. Other operating expenses. Other operating expenses of$28.5 million in 2020 were related primarily to transactions, changes in legal reserves, including settlements and reorganization. Other operating expenses of$199.4 million in 2019 were related primarily to reorganization, due to reductions in workforce, which resulted in the recognition of severance and other termination benefits, changes in legal reserves, including settlements, contract terminations and the proxy contest. See Note 1 to the Consolidated Financial Statements.
Other Income Statement Items
Gain on Equitrans Share Exchange. During the first quarter of 2020, we recognized a gain on the Equitrans Share Exchange as described in Note 5 to the Consolidated Financial Statements.
Loss on investment in Equitrans Midstream Corporation. Our investment in Equitrans Midstream is recorded at fair value by multiplying the closing stock price of Equitrans Midstream's common stock by the number of shares of Equitrans Midstream's common stock that we own. Changes in fair value are recorded in loss on investment in Equitrans Midstream Corporation in the Statements of Consolidated Operations. Our investment in Equitrans Midstream fluctuates with changes in Equitrans Midstream's stock price, which was$8.04 and$13.36 as ofDecember 31, 2020 and 2019, respectively. Note, the effect of the sale of 50% of our shares of Equitrans Midstream's common stock was recorded as a reduction to the investment in Equitrans Midstream in conjunction with our recognition of the gain on the Equitrans Share Exchange. See Note 5 to the Consolidated Financial Statements. Dividend and other income. The decrease in 2020 as compared to 2019 is due primarily to lower dividends received from our investment in Equitrans Midstream driven by the decrease in the number of shares of Equitrans Midstream's common stock that we own. Loss on debt extinguishment. During 2020, we recognized a loss on debt extinguishment related to the repayment of all or a portion of our 4.875% senior notes, 2.50% senior notes, 3.00% senior notes, floating rate notes and Term Loan Facility (defined and discussed in Note 10 to the Consolidated Financial Statements). See Note 10 to the Consolidated Financial Statements. 49 -------------------------------------------------------------------------------- Table of Contents Interest expense. Interest expense increased for 2020 compared to 2019 due to increased interest incurred on new debt issued in 2020 as well as interest incurred on letters of credit issued in 2020. These increases were partly offset by lower interest incurred due to the repayment of all or a portion of our 8.125% senior notes, 4.875% senior notes, floating rate notes and 2.50% senior notes and decreased borrowings on our credit facility. 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
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 ofDecember 31, 2020 were$24.8 billion , composed of$1.3 billion in 2021,$1.7 billion in 2022,$1.8 billion in 2023,$1.9 billion in 2024,$1.8 billion in 2025 and$16.3 billion primarily in 2026 through 2042. We also have commitments to purchase equipment, materials, frac sand for use as a proppant in our hydraulic fracturing operations and minimum volume commitments associated with certain water agreements. As ofDecember 31, 2020 , future commitments under these contracts were$96.5 million in 2021 and$14.3 million in 2022.
Contractual Commitments. We have contractual commitments under our debt agreements including interest payments and principal repayments. See Note 10 to the Consolidated Financial Statements for further discussion including the timing of principal repayments.
Unrecognized Tax Benefits. As discussed in Note 9 to the Consolidated Financial Statements, we had a total reserve for unrecognized tax benefits atDecember 31, 2020 of$181.2 million , of which$90.3 million is offset against deferred tax assets for general business tax credit carryforwards and NOLs. We are currently unable to make reasonably reliable estimates of the period of cash settlement of these potential liabilities with taxing authorities. 50 -------------------------------------------------------------------------------- Table of Contents Planned Capital Expenditures. In 2021, we expect to spend approximately$1.1 to$1.2 billion in total capital expenditures, excluding amounts attributable to noncontrolling interests. 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 2021 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.
Operating Activities
Net cash provided by operating activities was$1,538 million for 2020 compared to$1,852 million for 2019. The decrease was due primarily to lower cash operating revenues and unfavorable timing of working capital payments, partly offset by increased cash settlements received on derivatives not designated as hedges, income tax refunds, plus interest, received of$440 million during 2020 and lower cash operating expenses. Our cash flows from operating activities are affected by movements in the market price for commodities. We are unable to predict such movements outside of the current market view as reflected in forward strip pricing. Refer to Item 1A., "Risk Factors - Natural gas, NGLs and oil price volatility, or a prolonged period of low natural gas, NGLs and oil prices, may have an adverse effect on our revenue, profitability, future rate of growth, liquidity and financial position." for further information.
Investing Activities
Net cash used in investing activities was$1,556 million for 2020 compared to$1,601 million for 2019. The decrease was due to lower capital expenditures as a result of our change in strategic focus from production growth to capital efficiency as well as cash received from asset sales and the Equitrans Share Exchange. The decrease was partly offset by cash paid for acquisitions as described in Note 6.
The following table summarizes our capital expenditures.
Years Ended December 31,
2020 2019
(Millions)
Reserve development $ 839 $ 1,377
Land and lease (a) 121 195
Capitalized overhead 51 77
Capitalized interest 17 24
Other production infrastructure 40 97
Other corporate items 11 3
Total capital expenditures 1,079 1,773
(Deduct) add non-cash items (b) (37) (171)
Total cash capital expenditures $ 1,042 $ 1,602
(a)Capital expenditures attributable to noncontrolling interests were $4.9
million for the year ended December 31, 2020 .
(b)Represents the net impact of non-cash capital expenditures, including
capitalized share-based compensation costs, the effect of timing of receivables
from working interest partners and accrued capital expenditures. The impact of
accrued capital expenditures includes the reversal of the prior period accrual
as well as the current period estimate.
Financing Activities
Net cash provided by financing activities was$32 million for 2020 compared to net cash used in financing activities of$249 million for 2019. For 2020, the primary source of financing cash flows was net proceeds from the issuance of debt and equity and the primary use of financing cash flows was net repayments of debt. For 2019, the primary uses of financing cash flows were net repayments of debt and credit facility borrowings, and the primary source of financing cash flows was net proceeds from borrowings on the Term Loan Facility. See Note 10 to the Consolidated Financial Statements for further discussion of our debt.
On
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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 endedDecember 31, 2019 , which is incorporated herein by reference, for discussion and analysis of operating, investing and financing activities for the year endedDecember 31, 2018 .
Security Ratings and Financing Triggers
The table below reflects the credit ratings and rating outlooks assigned to our debt instruments atFebruary 12, 2021 . 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 further discussion of what is deemed investment grade. Rating agency Senior notes Outlook Moody's Investors Service (Moody's) Ba2 Stable Standard & Poor's Ratings Service (S&P) BB Stable Fitch Ratings Service (Fitch) BB Positive Changes in credit ratings may affect our access to the capital markets, the cost of short-term debt through interest rates and fees under our lines of credit, the interest rate on the Adjustable Rate Notes, the rates available on new long-term debt, our pool of investors and funding sources, the borrowing costs and margin deposit requirements on our OTC derivative instruments and credit assurance requirements, including collateral, in support of our midstream service contracts, joint venture arrangements or construction contracts. Margin deposits on our OTC derivative instruments are also subject to factors other than credit rating, such as natural gas prices and credit thresholds set forth in the agreements between us and hedging counterparties. As ofFebruary 12, 2021 , 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 ofFebruary 12, 2021 , such assurances could be up to approximately$1.0 billion , inclusive of letters of credit, OTC derivative instrument margin deposits and other collateral posted of approximately$0.9 billion in the aggregate. See Notes 3 and 10 to the Consolidated Financial Statements for further information. Our debt agreements and other financial obligations contain various provisions that, if not complied with, could result in default or event of default under our credit facility, mandatory partial or full repayment of amounts outstanding, reduced loan capacity or other similar actions. The most significant covenants and events of default under the debt agreements relate to maintenance of a debt-to-total capitalization ratio, limitations on transactions with affiliates, insolvency events, nonpayment of scheduled principal or interest payments, acceleration of other financial obligations and change of control provisions. Our credit facility contains financial covenants that require us to have a total debt-to-total capitalization ratio no greater than 65%. The calculation of this ratio excludes the effects of accumulated other comprehensive income. As ofDecember 31, 2020 , we were in compliance with all debt provisions and covenants.
See Note 10 to the Consolidated Financial Statements for a discussion of the borrowings under our credit facility.
Commodity Risk Management
The substantial majority of our commodity risk management program is related to
hedging sales of our produced natural gas. The overall objective of our hedging
program is to protect cash flows from undue exposure to the risk of changing
commodity prices. The derivative commodity instruments that we use are primarily
swap, collar and option agreements. The
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following table summarizes the approximate volumes and prices of our NYMEX hedge
positions through 2024 as of February 12, 2021 .
2021 (a) 2022 2023 2024
Swaps:
Volume (MMDth) 1,082 455 69 2
Average Price ($/Dth) $ 2.71 $ 2.66 $ 2.48 $ 2.67
Calls - Net Short:
Volume (MMDth) 407 284 77 15
Average Short Strike Price ($/Dth) $ 2.91 $ 2.89 $ 2.89 $ 3.11
Puts - Net Long:
Volume (MMDth) 227 135 69 15
Average Long Strike Price ($/Dth)$ 2.59 $ 2.35 $ 2.40 $ 2.45 Fixed Price Sales (b): Volume (MMDth) 72 4 3 - Average Price ($/Dth)$ 2.50 $ 2.38 $ 2.38 $ - (a)Full year 2021. (b)The difference between the fixed price and NYMEX price is included in average differential presented in our price reconciliation in the "Average Realized Price Reconciliation." The fixed price natural gas sales agreements can be physically or financially settled.
For 2021, 2022, 2023 and 2024, we have natural gas sales agreements for
approximately 18 MMDth, 18 MMDth, 88 MMDth and 11 MMDth, respectively, that
include average NYMEX ceiling prices of
During 2020, we purchased$47 million of net options with the primary purpose of reducing future NYMEX based payments that could be due in 2021, 2022 and 2023 to Equitrans Midstream related to the Henry Hub Cash Bonus (defined and discussed in Note 5 to the Consolidated Financial Statements) provided for by the Consolidated GGA. See Item 7A., "Quantitative and Qualitative Disclosures About Market Risk" and Note 3 to the Consolidated Financial Statements for further discussion of our hedging program.
Off-Balance Sheet Arrangements
See Note 17 to the Consolidated Financial Statements for a discussion of our guarantees.
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
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expenses and the related disclosure of contingent assets and liabilities. The
following critical accounting policies, which were reviewed by the Audit
Committee of our Board of Directors (the Audit Committee), relate to our more
significant judgments and estimates used in the preparation of our Consolidated
Financial Statements. Actual results could differ from our estimates.
Accounting for Gas, NGL and Oil Producing Activities. We use the successful efforts method of accounting for our oil and gas producing activities.
The carrying values of our proved oil and gas properties are reviewed for impairment when events or circumstances indicate that the remaining carrying value may not be recoverable. To determine whether impairment of our oil and gas properties has occurred, we compare the estimated expected undiscounted future cash flows to the carrying values of those properties. Estimated future cash flows are based on proved and, if determined reasonable by management, risk-adjusted probable reserves and assumptions generally consistent with the assumptions used by us for internal planning and budgeting purposes, including, among other things, the intended use of the asset, anticipated production from reserves, future market prices for natural gas, NGLs and oil adjusted for basis differentials, future operating costs and inflation. Proved oil and gas properties that have carrying amounts in excess of estimated future undiscounted cash flows are written down to fair value, which is estimated by discounting the estimated future cash flows using discount rates and other assumptions that marketplace participants would use in their fair value estimates. Capitalized costs of unproved oil and gas properties are evaluated for recoverability on a prospective basis at least annually. Indicators of potential impairment include changes due to economic factors, potential shifts in business strategy and historical experience. The likelihood of an impairment of unproved oil and gas properties increases as the expiration of a lease term approaches and drilling activity has not commenced. If we do not intend to drill on the property prior to expiration of the lease or do not have the intent and ability to extend, renew, trade or sell the lease prior to expiration, impairment expense is recorded. We believe accounting for gas, NGL and oil producing activities is a "critical accounting estimate" because the evaluations of impairment of proved properties involve significant judgment about future events, such as future sales prices of natural gas and NGLs and future production costs, as well as the amount of natural gas and NGLs recorded and timing of recoveries. 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 ofOil and Gas Properties " and Note 1 to the Consolidated Financial Statements for additional information on our impairments of proved and unproved oil and gas properties. 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 volumes 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. 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 ofOil and Gas Properties " for additional information on our oil and gas reserves. 54
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Income Taxes. We recognize deferred tax assets and liabilities for the expected future tax consequences of events that have been included in our Consolidated Financial Statements or tax returns. We have recorded deferred tax assets resulting from federal and state NOL carryforwards, an AMT credit carryforward, other federal tax credit carryforwards, unrealized capacity contract losses, incentive compensation and investments in securities. We have established a valuation allowance against a portion of the deferred tax assets related primarily to federal and state NOL carryforwards and our investment in Equitrans Midstream because we believe it is more likely than not that those deferred tax assets will not be fully realized. We established a valuation allowance against the state and part of the federal deferred tax asset related to our investment in Equitrans Midstream because the fair value loss is not expected to be fully realized for tax purposes due to capital loss limitations. No other significant valuation allowances have been established as we believe that future sources of taxable income, reversing temporary differences and other tax planning strategies will be sufficient to realize the deferred tax assets. Changes to our valuation allowance would impact our income tax expense and net income in the period in which such a determination is made.
We estimate the amount of financial statement benefit recorded for uncertain tax positions. See Note 9 to our Consolidated Financial Statements.
We believe income taxes are "critical accounting estimates" because we must assess the likelihood that our deferred tax assets will be recovered from future taxable income and exercise judgment on the amount of financial statement benefit recorded for uncertain tax positions. When evaluating whether or not a valuation allowance should be established, we exercise judgment on whether it is more likely than not (a likelihood of more than 50%) that a portion or all of the deferred tax assets will not be realized. To determine whether a valuation allowance is needed, we consider all available evidence, both positive and negative, including carrybacks, tax planning strategies, reversals of deferred tax assets and liabilities and forecasted future taxable income. To determine the amount of financial statement benefit recorded for uncertain tax positions, we consider the amounts and probabilities of outcomes that could be realized upon ultimate settlement of an uncertain tax position using facts, circumstances and information available at the reporting date. To the extent that a valuation allowance or uncertain tax position is established or increased or decreased during a period, we record an expense or benefit in income tax expense in our Statements of Consolidated Operations. 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.
We estimate the fair value of our financial instruments using quoted market
prices when available. If quoted market prices are not available, the fair value
is based on models that use market-based parameters, including forward curves,
discount rates, volatilities and nonperformance risk, as inputs. Nonperformance
risk considers the effect of our credit standing on the fair value of
liabilities and the effect of the counterparty's credit standing on the fair
value of assets. We estimate nonperformance risk by analyzing publicly available
market information, including a comparison of the yield on debt instruments with
credit ratings similar to our credit rating or the counterparty's credit rating
and the yield on a risk-free instrument. 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.
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.
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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.
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.
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. The rate relief was effected through the
execution the Consolidated GGA (defined and discussed in Note 5 to the
Consolidated Financial Statements). We recorded a contract asset representing
the estimated fair value of the rate relief provided by the Consolidated GGA.
Key assumptions used in the fair value calculation included an estimated
production volume forecast, a market-based discount rate and a
probability-weighted estimate of the in-service date of the Mountain Valley
Pipeline. Beginning with the Mountain Valley Pipeline in-service date, we will
recognize amortization of the contract asset over a period of approximately four
years in a manner consistent with the expected timing of our realization of the
economic benefits of the rate relief provided by the Consolidated GGA.
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 (defined and discussed in Note 10 to the Consolidated Financial Statements).
At issuance, we separated the Convertible Notes into liability and equity components. The carrying amount of the liability component was calculated by measuring the fair value of similar debt instruments that do not have associated convertible features. The carrying amount of the equity component, representing the conversion option, was determined by deducting the fair value of the liability component from the principal value of the Convertible Notes. The equity component is not remeasured as long as it continues to meet the condition for equity classification. The excess of the principal amount of the liability component over its carrying amount (the debt discount) will be amortized to interest expense over the term of the Convertible Notes using the effective interest rate method. Issuance costs were allocated to the liability and equity components of the Convertible Notes based on their relative fair values. In connection with the Convertible Notes offering, we entered into the Capped Call Transactions (defined and discussed in Note 10 to the Consolidated Financial Statements). The Capped Call Transactions are separate from the Convertible Notes. The Capped Call Transactions were recorded in shareholders' equity and were not accounted for as derivatives. The cost to purchase the Capped Call Transactions was recorded as a reduction to equity and will not be remeasured. Upon conversion of the Convertible Notes, we intend to use a combined settlement approach to satisfy our settlement obligation by paying or delivering to holders of the Convertible Notes cash equal to the principal amount of the obligation and EQT common stock for amounts that exceed the principal amount of the obligation. As such, we used the treasury stock method for the diluted earnings per share (EPS) calculation, and there is no adjustment to the diluted EPS numerator for the cash-settled portion of the instrument. We believe the accounting complexity of the Convertible Notes is a "critical accounting estimate" because we used judgment to determine the balance sheet classification, to determine the treatment of the Capped Call Transactions and to determine the existence of any derivatives that may require separate accounting under applicable accounting guidance. Future results of operations for any quarterly or annual period could be materially affected by changes in our assumptions.
Business Combinations. Accounting for a business combination requires a company to record the identifiable assets and liabilities acquired at fair value.
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In the fourth quarter of 2020, we completed the Chevron Acquisition. The most significant assumptions used in accounting for the Chevron Acquisition include those used to estimate the fair value of the oil and gas properties acquired, the acquired investment in midstream gathering assets and acquired contract liabilities. We calculated the fair value of the acquired proved oil and gas properties, including in-process wells, using a risk-adjusted after-tax discounted cash flow analysis that was based on the following key assumptions: future commodity prices, projections of estimated quantities of reserves, estimated future rates of production, projected reserve recovery factors, timing and amount of future development and operating costs and a weighted average cost of capital. We calculated the fair value of the acquired unproved properties using the guideline transaction method that was based on the following key assumptions: future development plans from a market participant perspective and value per undeveloped acre. We calculated the fair value of our investment in the midstream gathering assets primarily using a discounted cash flow analysis that was based on the following key assumptions: projected revenues, expenses and capital expenditures. We calculated the fair value of acquired contract liabilities using estimated future volumes and annual contract commitments calculated on a discounted basis that was based on the following key assumptions: estimated future volumes and market participant cost of debt. We believe business combinations are "critical accounting estimates" because the valuation of acquired assets and liabilities involves significant judgment about future events. Future results of operations for any quarterly or annual period could be materially affected by changes in our assumptions.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk and Derivative Instruments. Our primary market risk exposure is the volatility of future prices for natural gas and NGLs. Due to the volatility of commodity prices, we are unable to predict future potential movements in the market prices for natural gas and NGLs at our ultimate sales points and, thus, cannot predict the ultimate impact of prices on our operations. Prolonged low, or significant, extended declines in, natural gas and NGLs prices could adversely affect, among other things, our development plans, which would decrease the pace of development and the level of our proved reserves. Increases in natural gas and NGLs prices may be accompanied by, or result in, increased well drilling costs, increased production taxes, increased lease operating expenses, increased volatility in seasonal gas price spreads for our storage assets and increased end-user conservation or conversion to alternative fuels. In addition, to the extent we have hedged our production at prices below the current market price, we will not benefit fully from an increase in the price of natural gas. The overall objective of our hedging program is to protect cash flows from undue exposure to the risk of changing commodity prices. Our use of derivatives is further described in Note 3 to the Consolidated Financial Statements and "Commodity Risk Management" under "Capital Resources and Liquidity" in Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations." Our OTC derivative commodity instruments are placed primarily with financial institutions and the creditworthiness of those institutions is regularly monitored. We primarily enter into derivative instruments to hedge forecasted sales of production. We also enter into derivative instruments to hedge basis and exposure to fluctuations in interest rates. Our use of derivative instruments is implemented under a set of policies approved by ourHedge and Financial Risk Committee and reviewed by our Board of Directors. For derivative commodity instruments used to hedge our forecasted sales of production, which are at, for the most part, NYMEX natural gas prices, we set policy limits relative to the expected production and sales levels that are exposed to price risk. We have an insignificant amount of financial natural gas derivative commodity instruments for trading purposes. The derivative commodity instruments we use 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. We use these agreements to hedge our NYMEX and basis exposure. We may also use other contractual agreements when executing our commodity hedging strategy. We monitor price and production levels on a continuous basis and make adjustments to quantities hedged as warranted. A hypothetical decrease of 10% in the market price of natural gas onDecember 31, 2020 and 2019 would increase the fair value of our natural gas derivative commodity instruments by approximately$501 million and$389 million , respectively. A hypothetical increase of 10% in the market price of natural gas onDecember 31, 2020 and 2019 would decrease the fair value of our natural gas derivative commodity instruments by approximately$495 million and$395 million , respectively. For purposes of this analysis, we applied the 10% change in the market price of natural gas onDecember 31, 2020 and 2019 to our natural gas derivative commodity instruments as ofDecember 31, 2020 and 2019 to calculate the hypothetical change in fair value. The change in fair value was determined using a method similar to our normal process for determining derivative commodity instrument fair value described in Note 4 to the Consolidated Financial Statements. 57
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The above analysis of our derivative commodity instruments does not include the offsetting impact that the same hypothetical price movement may have on our physical sales of natural gas. The portfolio of derivative commodity instruments held to hedge our forecasted produced gas approximates a portion of our expected physical sales of natural gas; therefore, an adverse impact to the fair value of the portfolio of derivative commodity instruments held to hedge our forecasted production associated with the hypothetical changes in commodity prices referenced above should be offset by a favorable impact on our physical sales of natural gas, assuming that the derivative commodity instruments are not closed in advance of their expected term and the derivative commodity instruments continue to function effectively as hedges of the underlying risk. If the underlying physical transactions or positions are liquidated prior to the maturity of the derivative commodity instruments, a loss on the financial instruments may occur or the derivative commodity instruments might be worthless as determined by the prevailing market value on their termination or maturity date, whichever comes first. Interest Rate Risk. Changes in market interest rates affect the amount of interest we earn on cash, cash equivalents and short-term investments and the interest rates we pay on borrowings on our credit facility and, prior to its full redemption onJune 30, 2020 , our Term Loan Facility. None of the interest we pay on our senior notes fluctuates based on changes to market interest rates. A 1% increase in interest rates on our borrowings on our credit facility and term loan facility during the year endedDecember 31, 2020 would have increased 2020 annual interest expense by approximately$5 million . A 1% increase in interest rates on our borrowings under our credit facility, term loan facility and floating rate notes during the year endedDecember 31, 2019 would have increased 2019 annual interest expense by approximately$14 million . Interest rates on the Adjustable Rate Notes fluctuate based on changes to the credit ratings assigned to our senior notes by Moody's, S&P and Fitch. For a discussion of credit rating downgrade risk, see Item 1A., "Risk Factors - Our exploration and production operations have substantial capital requirements, and we may not be able to obtain needed capital or financing on satisfactory terms." Changes in interest rates affect the fair value of our fixed rate debt. See Note 10 to the Consolidated Financial Statements for further discussion of our debt and Note 4 to the Consolidated Financial Statements for a discussion of fair value measurements, including the fair value of our debt. Other Market Risks. We are exposed to credit loss in the event of nonperformance by counterparties to our derivative contracts. This credit exposure is limited to derivative contracts with a positive fair value, which may change as market prices change. Our 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. We use various processes and analyses to monitor and evaluate our 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, we enter into transactions primarily with financial counterparties that are of investment grade, enter into netting agreements whenever possible and may obtain collateral or other security. Approximately 47%, or$456 million , of our OTC derivative contracts outstanding atDecember 31, 2020 had a positive fair value. Approximately 75%, or$718 million , of our OTC derivative contracts outstanding atDecember 31, 2019 had a positive fair value. As ofDecember 31, 2020 , we were not in default under any derivative contracts and had no knowledge of default by any counterparty to our derivative contracts. During the year endedDecember 31, 2020 , we made no adjustments to the fair value of our derivative contracts due to credit related concerns outside of the normal non-performance risk adjustment included in our established fair value procedure. We monitor market conditions that may impact the fair value of our derivative contracts. We are exposed to the risk of nonperformance by credit customers on physical sales of natural gas, NGLs and oil. Revenues and related accounts receivable from our operations are generated primarily from the sale of produced natural gas, NGLs and oil to marketers, utilities and industrial customers located in theAppalachian Basin and in markets that are accessible through our transportation portfolio, which includes markets in theGulf Coast , Midwest andNortheast United States andCanada . We also contract with certain processors to market a portion of NGLs on our behalf. No one lender of the large group of financial institutions in the syndicate for our credit facility holds more than 10% of the financial commitments under such facility. The large syndicate group and relatively low percentage of participation by each lender are expected to limit our exposure to disruption or consolidation in the banking industry. 58
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