What changed in this filing

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Item 1. Financial Statements

2022-04-26 compared with 2021-10-26 · 350 added, 644 removed, 936 unchanged (52% of the section changed)

3 unchanged sentences

(In thousands, except per share data)

September 30,

Current assets:

1 unchanged sentence

Accounts receivable, less allowance for doubtful accounts of $ 568 and $ 568

Contingent consideration receivable

Derivative assets

7 unchanged sentences

Operating lease right-of-use assets

Deferred tax assets

Current liabilities:

7 unchanged sentences

Total current liabilities

Senior subordinated notes

Deferred tax liabilities

7 unchanged sentences

Stockholders’

Preferred stock, $ 1 par, 10,000,000 shares authorized, no ne issued and outstanding

Preferred stock, $ 1 par, 10,000,000 shares authorized, none issued and outstanding

Common stock, $ 0.01 par, 475,000,000 shares authorized, 262,777,606 issued at

September 30, 2021 and 256,353,887 issued at December 31, 2020

Common stock held in treasury, 10,002,646 shares at September 30, 2021 and 10,005,795

March 31, 2022 and 259,795,554 issued at December 31, 2021

Common stock held in treasury, 10,601,535 shares at March 31, 2022 and 10,002,646

shares at December 31, 2021

8 unchanged sentences

(Unaudited, in thousands, except per share data)

Three Months Ended September 30,

Nine Months Ended September 30,

Three Months Ended March 31,

Revenues and other income:

Natural gas, NGLs and oil sales

Derivative fair value (loss) income

Derivative fair value loss

Brokered natural gas, marketing and other

9 unchanged sentences

Deferred compensation plan

Loss (gain) on early extinguishment of debt

Loss on early extinguishment of debt

Depletion, depreciation and amortization

Impairment of proved properties and other assets

(Gain) loss on the sale of assets

Total costs and expenses

Loss before income taxes

(Loss) income before income taxes

Income tax expense (benefit):

Net loss per common share:

Net (loss) income

Net (loss) income per common share:

Weighted average common shares outstanding:

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RANGE RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF COMP REHENSIVE LOSS

CONSOLIDATED STATEMENTS OF COMP REHENSIVE (LOSS) INCOME

(Unaudited, in thousands)

Three Months Ended September 30,

Nine Months Ended September 30,

Other comprehensive loss:

Three Months Ended March 31,

Net (loss) income

Other comprehensive income:

Postretirement benefits:

Actuarial gain

Amortization of prior service costs

Income tax expense

Total comprehensive loss

Total comprehensive (loss) income

The accompanying notes are an integral part of these consolidated financial statements.

2 unchanged sentences

(Unaudited, in thousands)

Nine Months Ended September 30,

Three Months Ended March 31,

Operating activities:

Adjustments to reconcile net loss to net cash provided from operating activities:

Deferred income tax benefit

Net (loss) income

Adjustments to reconcile net (loss) income to net cash provided from operating activities:

Deferred income tax (benefit) expense

Depletion, depreciation and amortization and impairment of proved properties

Abandonment and impairment of unproved properties

Derivative fair value loss (income)

Derivative fair value loss

Cash settlements on derivative financial instruments

Divestiture contract obligation, including accretion, net of gain

Allowance for bad debt

Amortization of deferred financing costs and other

Deferred and stock-based compensation

Gain on the sale of assets

Loss (gain) on early extinguishment of debt

(Gain) loss on the sale of assets

Loss on early extinguishment of debt

Changes in working capital:

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Proceeds from the sales of common stock held by the deferred compensation

Net cash used in financing activities

Increase (decrease) in cash and cash equivalents

Net cash (used in) provided from financing activities

Decrease in cash and cash equivalents

Cash and cash equivalents at beginning of period

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Balance as of March 31, 2022

Issuance of common stock

Stock-based compensation

Treasury stock

Other comprehensive income

Balance as of June 30, 2021

Issuance of common stock

Stock-based compensation

Treasury stock

Other comprehensive income

Balance as of September 30, 2021

The accompanying notes are an integral part of these consolidated financial statements.

6 unchanged sentences

Issuance of common stock

Stock-based compensation

Treasury stock

Other comprehensive income

Balance as of March 31, 2020

Issuance of common stock

upon vesting of PSUs

2 unchanged sentences

Other comprehensive income

Balance as of June 30, 2020

Issuance of common stock

Stock-based compensation

Treasury stock

Other comprehensive income

Balance as of September 30, 2020

Balance as of March 31, 2021

The accompanying notes are an integral part of these consolidated financial statements.

11 unchanged sentences

These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in our 2021 Annual Report on Form 10-K filed with the SEC on February 22, 2022.

The results of operations for third quarter and nine months ended September 30, 2021 are not necessarily indicative of the results to be expected for the full year.

As more fully described in Note 2 and Note 18 of our 2020 Annual Report on Form 10-K filed with the SEC, deferred tax expense (benefit) for the first, second and third quarters 2020 was corrected through a restatement.

The results of operations for three months ended March 31, 2022 are not necessarily indicative of the results to be expected for the full year.

(3) NEW ACCOUNTING STANDARDS

Not Yet Adopted

None that are expected to have a material impact on our financial statements.

(4) DISPOSITIONS

We recognized a pretax net gain of $ 78,000 on the sale of assets in third quarter 2021 compared to a pretax net loss of $ 9.2 million in third quarter 2020 and a pretax net gain of $ 724,000 in first nine months 2021 compared to a pretax net gain of $ 112.4 million in first nine months 2020.

See discussion below for further details.

2021 Dispositions

North Louisiana .

In second quarter 2021, we recorded an additional gain on the sale of our North Louisiana assets, which closed in third quarter 2020, of $ 2.4 million, which is primarily related to final closing adjustments.

In first quarter 2021, we recorded an additional loss on the sale of these North Louisiana assets of $ 1.9 million.

2020 Dispositions

North Louisiana.

In August 2020, we completed the sale of our North Louisiana assets for total consideration having an estimated fair value of $ 260.0 million.

This estimated fair value reflected (i) cash proceeds of $ 245.0 million, before normal closing adjustments and (ii) $ 15.0 million in contingent consideration which represents the estimated fair value, on August 14, 2020, of the contingent consideration we are entitled to receive in the future should certain commodity price thresholds be met.

We recorded a pretax loss of $ 8.1 million, after closing adjustments, in third quarter 2020.

Divestiture contingent consideration.

We are entitled to receive contingent consideration, annually through 2023, based on future achievement of certain natural gas and oil prices based on published indexes along with the realized NGLs price of the buyer.

The fair value of the contingent consideration is classified as current and noncurrent derivative asset on our consolidated balance sheet.

We revalue the contingent consideration each reporting period, with any valuation changes being recorded as derivative fair value income or loss in our consolidated statements of operations.

See also Note 11 for additional information.

Divestiture contract obligation.

As part of the sale of our North Louisiana assets, we retained certain midstream gathering, transportation and processing obligations through 2030.

The divestiture contract obligation is included in current or non-current liabilities in our consolidated balance sheet based on the forecasted timing of payments.

These costs are recognized in exit and termination costs in our consolidated statements of operations.

See also Note 14 for additional information.

Pennsylvania .

In first quarter 2020, we completed the sale of our shallow legacy assets in northwestern Pennsylvania for proceeds of $ 1.0 million.

Based upon the receipt of approval from state governmental authorities of a change in operatorship during first quarter, we recognized a pretax gain of $ 122.5 million primarily due to the elimination of the asset retirement obligation associated with these properties.

No accounting standards were adopted in first quarter 2022 that had a material impact on our consolidated financial statements.

(4) REVENUES FROM CONTRACTS WITH CUSTOMERS

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Brokered revenue attributable to each product sales type is included here because the volume of product that we purchase is subsequently sold to separate counterparties in accordance with existing sales contracts under which we also sell our production.

Accounts receivable attributable to our revenue contracts with customers was $ 361.9 million at September 30, 2021 and $ 237.8 million at December 31, 2020.

Accounts receivable attributable to our revenue contracts with customers was $ 416.2 million at March 31, 2022 and $ 460.2 million at December 31, 2021.

Revenue attributable to each of our identified revenue streams is disaggregated below (in thousands):

Three Months Ended

September 30,

Nine Months Ended

September 30,

Natural gas sales

3 unchanged sentences

Other marketing revenue (1)

The nine months ended September 30, 2021 includes $ 8.8 million received as part of a capacity release agreement.

(1) The three months ended March 31, 2021 includes $ 8.8 million received as part of a capacity release agreement.

(5) INCOME TAXES

3 unchanged sentences

Income taxes for discrete items are computed and recorded in the period that a specific transaction occurs.

For the three months and nine months ended September 30, 2021 and 2020, our overall effective tax rate was different than the federal statutory rate due primarily to state income taxes, equity compensation, valuation allowances and other tax items.

For the three months ended

March 31, 2022 and 2021, our overall effective tax rate was different than the federal statutory rate due primarily to state income taxes, equity compensation, valuation allowances and other tax items.

Current income taxes reflect estimated state income taxes due for 2022 which is based on our estimated earnings, taking into account state tax rates and laws regarding NOL limitations.

4 unchanged sentences

Three Months Ended

September 30,

Nine Months Ended

September 30,

Net loss, as reported

Net (loss) income, as reported

Participating earnings (a)

Basic net loss attributed to common shareholders

Basic net (loss) income attributed to common

Reallocation of participating earnings (a)

Diluted net loss attributed to common

Net loss per common share:

Diluted net (loss) income attributed to common

Net (loss) income per common share:

Restricted Stock Awards represent participating securities because they participate in nonforfeitable dividends or distributions with common equity owners.

3 unchanged sentences

Three Months Ended

September 30,

Nine Months Ended

September 30,

Weighted average common shares outstanding –

basic and diluted

Weighted average common shares outstanding-basic for third quarter 2021 excludes 6.5 million shares of restricted stock held in our deferred compensation plan compared to 6.2 million shares in third quarter 2020 (although all awards are issued and outstanding upon grant).

Weighted average common shares outstanding-basic for first nine months 2021 excludes 6.6 million shares of restricted stock compared to 5.3 million for first nine months 2020.

Due to our net loss for third quarter and first nine months 2021 and 2020, we excluded all equity-grants from the computation of diluted loss per share because the effect would have been anti-dilutive to the computations.

Effect of dilutive securities:

Director and employee restricted stock and performance

based equity awards

Weighted average common shares outstanding –

Weighted average common shares outstanding-basic for first quarter 2022 excludes 6.2 million shares of restricted stock held in our deferred compensation plan compared to 6.2 million shares in first quarter 2021 (although all awards are issued and outstanding upon grant).

Due to our loss in first quarter 2022, we excluded all outstanding equity grants from the computation of diluted loss per share because the effect would have been anti-dilutive to the computations.

For first quarter 2021, equity grants of 88,000 were outstanding but not included in the computation of diluted net income per share because the grant prices were greater than the average market price of our common shares and would be anti-dilutive to the computation.

Non-vested restricted stock and performance based equity awards are included in the computation using the treasury stock method with the deemed proceeds equal to the average unrecognized compensation during the period.

(7) Capitalized Costs and Accumulated Depreciation, Depletion and Amortization (a)

September 30,

(in thousands)

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(8) INDEBTEDNESS

We had the following debt outstanding as of the dates shown below (bank debt interest rate at September 30, 2021 is shown parenthetically).

No interest was capitalized during the nine months ended September 30, 2021 or the year ended December 31, 2020 (in thousands).

September 30,

Bank debt ( 2.4 %)

We had the following debt outstanding as of the dates shown below.

No interest was capitalized during the three months ended March 31, 2022 or the year ended December 31, 2021 (in thousands).

Senior notes:

6 unchanged sentences

9.25 % senior notes due 2026

Other senior notes due 2022

Total senior notes

Senior subordinated notes:

5.00 % senior subordinated notes due 2022

5.00 % senior subordinated notes due 2023

5.75 % senior subordinated notes due 2021

Total senior subordinated notes

Unamortized premium

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The bank credit facility also provides for a borrowing base subject to periodic redeterminations and for event-driven unscheduled redeterminations.

As of September 30, 2021, our bank group was composed of twenty-five financial institutions.

As of March 31, 2022, our bank group was composed of twenty-six financial institutions.

The borrowing base may be increased or decreased based on our request and sufficient proved reserves, as determined by the bank group.

The commitment amount may be increased to the borrowing base, subject to payment of a mutually acceptable commitment fee to those banks agreeing to participate in the facility increase.

Borrowings under the bank credit facility can either be at the alternate base rate (ABR, as defined in the bank credit facility agreement) plus a spread ranging from 0.25 % to 1.25 % or LIBOR borrowings at the LIBOR Rate (as defined in the bank credit facility agreement) plus a spread ranging from 1.25 % to 2.25 %.

Borrowings under the bank credit facility can either be at the alternate base rate (ABR, as defined in the bank credit facility agreement) plus a spread ranging from 0.75 % to 1.75 % or at the LIBOR Rate (as defined in the bank credit facility agreement) plus a spread ranging from 1.75 % to 2.75 %.

The applicable spread is dependent upon borrowings relative to the borrowing base.

We may elect, from time to time, to convert all or any part of our LIBOR loans to base rate loans or to convert all or any of the base rate loans to LIBOR loans.

The weighted average interest rate was 2.0 % for third quarter 2021 compared to 2.4 % for third quarter 2020.

The weighted average interest rate was 2.1 % for first nine months 2021 compared to 2.7 % for first nine months 2020.

The weighted average interest rate was 2.5 % for first quarter 2022 compared to 2.2 % for first quarter 2021.

A commitment fee is paid on the undrawn balance based on an annual rate of 0.30 % to 0.375 %.

At September 30, 2021, the commitment fee was 0.30 % and the interest rate margin was 1.75 % on our LIBOR loans and 0.75 % on our ABR loans.

As part of our redetermination completed in September 2021, our borrowing base was reaffirmed for $ 3.0 billion and our bank commitment was also reaffirmed at $ 2.4 billion.

On September 30, 2021, bank commitments totaled $ 2.4 billion and the outstanding balance under our bank credit facility was $ 30.0 million, before deducting debt issuance costs.

At March 31, 2022, the commitment fee was 0.30 % and the interest rate margin was 1.75 % on our LIBOR loans and 0.75 % on our ABR loans.

On March 31, 2022, bank commitments totaled $ 2.4 billion and we had no borrowings outstanding on our bank credit facility.

Additionally, we had $ 338.0 million of undrawn letters of credit, leaving $ 2.1 billion of committed borrowing capacity available under the facility.

On April 14, 2022, we entered into an amended and restated revolving bank facility with JPMorgan Chase Bank, N.A.

as Administrative Agent and other lenders and agents party thereto.

The new facility has a maximum facility amount of $ 4.0 billion and a current elected borrowing base of $ 3.0 billion.

On April 14, 2022, the bank commitments totaled $ 1.5 billion.

The maturity of the new bank credit facility is April 14, 2027 .

The financial covenants include a maximum consolidated debt to EBITDAX ratio of 3.75 x and a minimum current ratio of 1.0 x (each ratio as defined in the bank credit facility).

Revisions were also made to replace LIBOR as a benchmark interest rate with SOFR or the secured overnight financing rate.

Our bank group is now composed of seventeen financial institutions.

New Senior Notes

In January 2022, we issued $ 500.0 million aggregate principal amount of 4.75 % senior notes due 2030 (the "4.75% Notes") for net proceeds of $ 492.1 million after underwriting expenses and commissions of $ 7.9 million.

The notes were issued at par.

The 8.25% Notes were offered to qualified institutional buyers and to non-U.S.

persons outside the United States in compliance with Rule 144A and Regulation S of the Securities Act of 1933, as amended (the Securities Act).

Interest due on the 8.25%

Notes is payable semi-annually in January and July and is unconditionally guaranteed on a senior unsecured basis by all of our subsidiary guarantors.

On or after January 15, 2027, we may redeem the 8.25% Notes, in whole or in part and from time to time, at 100 % of the principal amounts plus accrued and unpaid interest.

The 4.75 % Notes, issued at par, were offered to qualified institutional buyers and to non-U.S.

persons outside the United States in compliance with Rule 144A (for life) and Regulation S of the Securities Act of 1933, as amended (the "Securities Act").

Interest due on the 4.75 % Notes is payable semi-annually in February and August and is unconditionally guaranteed on a senior unsecured basis by all of our subsidiary guarantors.

On or after February 1, 2027, we may redeem the 4.75 % Notes, in whole or in part and from time to time, at 100 % of the principal amounts plus accrued and unpaid interest.

We may redeem the notes prior to their maturity at redemption prices based on a premium, plus accrued and unpaid interest as described in the indenture governing the 4.75 % Notes.

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The 4.75 % Notes are unsecured and are subordinated to all of our existing and future secured debt, rank equally with all of our existing and future unsecured debt and rank senior to all of our existing and future subordinated debt.

On the closing of the issuance of the 8.25% Notes, we used the proceeds to repay borrowings under our bank credit facility.

On the closing of the issuance of the 4.75 % Notes, we used the proceeds, along with cash on hand and our bank credit facility, to redeem $ 850.0 million of our 9.25 % senior notes due 2026.

Early Redemption

In first quarter 2021, based on the terms of the indentures governing certain of our senior and senior subordinated notes, we notified the trustee that we were electing to redeem the outstanding principal amounts of the following notes (in thousands):

5.75% senior notes due 2021

5.875% senior notes due 2022

5.75% senior subordinated notes 2021

5.00% senior subordinated notes 2022

5.00% senior subordinated notes 2023

The redemption price equaled 100 % of the unpaid principal plus accrued and unpaid interest.

The redemption date was April 2, 2021.

We recognized a loss on early extinguishment of debt in second quarter 2021 of approximately $ 63,000 which represents expensing of the remaining deferred financing costs.

In first quarter 2022, we announced a call for the redemption of $ 850.0 million of our outstanding 9.25% senior notes due 2026 .

The redemption price equaled 106.938 % of par plus accrued and unpaid interest.

The redemption date was February 1, 2022.

We recognized a loss on early extinguishment of debt in first quarter 2022 of $ 69.2 million which represents expensing of the remaining deferred financing costs and the call premium costs.

If we experience a change of control, noteholders may require us to repurchase all or a portion of our senior notes at 101 % of the aggregate principal amount plus accrued and unpaid interest, if any.

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Our bank credit facility contains negative covenants that limit our ability, among other things, to pay cash dividends, incur additional indebtedness, sell assets, enter into certain hedging contracts, change the nature of our business or operations, merge, consolidate or make certain investments.

In addition, we are required to maintain a ratio of EBITDAX (as defined in the bank credit facility agreement) to cash interest expense of equal to or greater than 2.5 and a current ratio (as defined in the bank credit facility agreement) of no less than 1.0 .

Through March 31, 2022, we were required to maintain a ratio of EBITDAX (as defined in the bank credit facility agreement) to cash interest expense of equal to or greater than 2.5 and a current ratio (as defined in the bank credit facility agreement) of no less than 1.0 .

In addition, the ratio of the present value of proved reserves (as defined in the bank credit facility agreement) to total debt must be equal to or greater than 1.5 until Range has two investment grade ratings.

We were in compliance with applicable covenants under the bank credit facility at September 30, 2021.

We were in compliance with applicable covenants under the bank credit facility at March 31, 2022.

( 9) ASSET RETIREMENT OBLIGATIONS

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The inputs are calculated based on historical data as well as current estimated costs.

A reconciliation of our liability for plugging

and abandonment costs for the nine months ended September 30, 2021 and the year ended December 31, 2020 is as follows (in thousands):

September 30,

A reconciliation of our liability for plugging and abandonment costs for the three months ended March 31, 2022 and the year ended December 31, 2021 is as follows (in thousands):

Beginning of period

1 unchanged sentence

Liabilities settled

Disposition of wells

Accretion expense

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We do not enter into these arrangements for speculative or trading purposes.

We utilize commodity swaps, calls, collars, three-way collars or swaptions to (1) reduce the effect of price volatility of the commodities we produce and sell and (2) support our annual capital budget and expenditure plans.

The fair value of our derivative contracts, represented by the estimated amount that would be realized upon termination, based on a comparison of the contract price and a reference price, generally the New York Mercantile Exchange (NYMEX) for natural gas and crude oil or Mont Belvieu for NGLs, approximated a net loss of $ 776.1 million at September 30, 2021.

We utilize commodity swaps, collars, three-way collars or swaptions to (1) reduce the effect of price volatility of the commodities we produce and sell and (2) support our annual capital budget and expenditure plans.

These contracts expire monthly through December 2024.

The following table sets forth our commodity-based derivative volumes by year as of September 30, 2021, excluding our basis and freight swaps and divestiture contingent consideration which are discussed separately below:

The following table sets forth our commodity-based derivative volumes by year as of March 31, 2022, excluding our basis swaps and divestiture contingent consideration which are discussed separately below:

Contract Type

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149,863 Mmbtu/day

January - March 2022

200,000 Mmbtu/day

60,000 Mmbtu/day

6,833 bbls/day

5,123 bbls/day

NGLs (C3-Propane)

6,000 bbls/day

NGLs (C2-Ethane)

April-June 2022

2,681 bbls/day

$ 1.20 /gallon

NGLs (NC4-Normal Butane)

NGLs (C3-Propane)

April-June 2022

3,989 bbls/day

NGLs (NC4-Butane)

April-June 2022

3,000 bbls/day

2 unchanged sentences

1,530 bbls/day

January - March 2022

2,656 bbls/day

January - March 2022

2,000 bbls/day

We also sold natural gas call swaptions of 80,000 Mmbtu/day for 2022 at a weighted average price of $ 2.80 and 70,000 Mmbtu/day for 2023 at a weighted average price of $3.04 .

We also sold natural gas call swaptions of 100,000 Mmbtu/day for 2023 at a weighted average price of $ 3.21 Mmbtu/day .

Every derivative instrument is required to be recorded on the balance sheet as either an asset or a liability measured at its fair value.

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Basis Swap Contracts

In addition to the swaps, collars and swaptions described above, at September 30, 2021, we had natural gas basis swap contracts which lock in the differential between NYMEX Henry Hub and certain of our physical pricing indices.

In addition to the swaps, collars and swaptions described above, at March 31, 2022, we had natural gas basis swap contracts which lock in the differential between NYMEX Henry Hub and certain of our physical pricing indices.

These contracts settle monthly through December 2024 and include a total volume of 187,405,000 Mmbtu.

The fair value of these contracts was a gain of $ 8.5 million at September 30, 2021.

At September 30, 2021, we also had propane spread swap contracts which lock in the differential between Mont Belvieu and international propane indices.

The contracts settle monthly through 2022.

The fair value of these contracts was a gain of $ 394,000 at September 30, 2021.

Freight Swap Contracts

In connection with our international propane sales, we utilize propane swaps.

To further hedge our propane price, at September 30, 2021, we had freight swap contracts on the Baltic Exchange which lock in the freight rate for a specific trade route.

These contracts settle monthly and cover 12,000 metric tons for the remainder of 2021 and cover 7,000 metric tons for first quarter 2022.

The fair value of these contracts equal to a loss of $ 26,000 at September 30, 2021.

The fair value of these contracts was a gain of $ 22.5 million at March 31, 2022.

Divestiture Contingent Consideration

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All changes in the fair value are recognized as a gain or loss in earnings in the period they occur in derivative fair value income or loss in our consolidated statements of operations.

For first nine months 2021, this fair value has increased $ 34.3 million for a fair value of $ 50.2 million as of September 30, 2021.

For first three months 2022, this fair value has increased $ 8.1 million for a fair value of $ 34.8 million as of March 31, 2022.

Derivative Assets and Liabilities

The combined fair value of derivatives included in the accompanying consolidated balance sheets as of September 30, 2021 and December 31, 2020 is summarized below.

The combined fair value of derivatives included in the accompanying consolidated balance sheets as of March 31, 2022 and December 31, 2021 is summarized below.

The assets and liabilities are netted where derivatives with both gain and loss positions are held by a single counterparty and we have master netting arrangements.

The tables below provide additional information relating to our master netting arrangements with our derivative counterparties (in thousands):

September 30, 2021

March 31, 2022

Offset in the

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Derivative assets:

–swaps

–collars

–three-way collars

–basis swaps

–swaps

–C3 propane spread swaps

−C5 natural gasoline swaps

−swaps

Divestiture contingent consideration

September 30, 2021

March 31, 2022

(Liabilities)

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Balance Sheet

of (Liabilities) Presented

Net Amounts of

(Liabilities)

Presented in the

Balance Sheet

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–three-way collars

–calls

–basis swaps

–swaps

–C3 propane spread swaps

–C2 ethane swaps

–C3 propane swaps

–C3 collars

–NC4 butane swaps

–NC4 butane collars

–C5 natural gasoline swaps

–C5 natural gasoline collars

–swaps

December 31, 2021

Gross Amounts

of Recognized

Offset in the

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Net Amounts of

Assets Presented in the

Balance Sheet

Assets Presented

in the Balance Sheet

Derivative assets:

4 unchanged sentences

–swaps

–C3 propane spread swaps

–C3 propane collars

–C3 propane spread

–C5 natural gasoline swaps

–C5 natural gasoline collars

–swaps

1 unchanged sentence

December 31, 2021

(Liabilities)

Gross Amounts

Offset in the

Balance Sheet

Recognized (Liabilities)

Amounts Offset

in the Balance Sheet

Net Amounts of

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–three-way collars

–calls

–basis swaps

–swaps

–C3 propane spread swaps

–C3 propane swaps

–C3 propane collars

–C3 propane spread

–C5 natural gasoline swaps

–C5 natural gasoline calls

–NC4 butane swaps

–NC4 butane collars

–C5 natural gasoline collars

–swaps

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Three Months Ended

September 30,

Nine Months Ended

September 30,

Commodity swaps

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These standards establish a fair value hierarchy that prioritizes the inputs used in applying the various valuation techniques.

Inputs broadly refer to the assumptions that market participants use to make

pricing decisions, including assumptions about risk.

Inputs broadly refer to the assumptions that market participants use to make pricing decisions, including assumptions about risk.

Level 1 inputs are given the highest priority in the fair value hierarchy while Level 3 inputs are given the lowest priority.

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The following tables present the fair value hierarchy for assets and liabilities measured at fair value, on a recurring basis (in thousands):

Fair Value Measurements at September 30, 2021 using:

Fair Value Measurements at March 31, 2022 using:

Quoted Prices

Identical Assets

September 30,

Trading securities held in the deferred compensation

3 unchanged sentences

–three-way collars

–calls

–basis swaps

–swaptions

Derivatives–freight swaps

Divestiture contingent consideration

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–swaptions

Derivatives–freight swaps

–freight swaps

Divesture contingent consideration

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Derivatives in Level 2 are measured at fair value with a market approach using third-party pricing services which have been corroborated with data from active markets or broker quotes.

As of September 30, 2021, a portion of our natural gas and oil derivative instruments contain swaptions where the counterparty has the right, but not the obligation, to enter into a fixed price swap on a pre-determined date.

As of March 31, 2022, a portion of our natural gas and oil derivative instruments contain swaptions where the counterparty has the right, but not the obligation, to enter into a fixed price swap on a pre-determined date.

If exercised, the swaption contract becomes a swap treated consistently with our fixed-price swaps.

In addition to our swaptions in Level 3 at September 30, 2021, we have NGLs collars.

In addition to our swaptions in Level 3 at March 31, 2022, we have NGLs collars.

Derivatives in Level 3 are also measured at fair value with a market approach using third-party pricing services which have been corroborated with data from active markets or broker quotes.

However, the subjectivity in the volatility factors utilized can cause a significant change in the fair value measurement of our derivatives in Level 3 and is considered a significant unobservable input.

At September 30, 2021, for our swaptions, we used a weighted average implied volatility of 40 % for natural gas.

At March 31, 2022, for our swaptions, we used a weighted average implied volatility of 36 % for natural gas.

We also utilized a range of implied volatilities from 44 % to 77 % for our NGLs collars with a weighted average implied volatility of 56 %.

The following is a reconciliation of the beginning and ending balances for derivative instruments classified as Level 3 in the fair value hierarchy (in thousands):

September 30,

Balance at December 31, 2021

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Transfers out of Level 3

Balance at September 30, 2021

Balance at March 31, 2022

Divestiture Contingent Consideration.

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Interest, dividends, and mark-to-market gains or losses are included in deferred compensation plan expense in the accompanying consolidated statements of operations.

For third quarter 2021, interest and dividends were $ 314,000 and the mark-to-market adjustment was a loss of $ 1.2 million compared to interest and dividends of $ 114,000 and a mark-to-market gain of $ 3.2 million in third quarter 2020.

For first nine months 2021, interest and dividends were $ 541,000 and the mark-to-market adjustment was a gain of $ 3.1 million compared to interest and dividends of $ 385,000 and a mark-to-market adjustment of a gain of $ 234,000 in first nine months 2020.

Fair Values –

Non-recurring

Certain assets are measured at fair value on a non-recurring basis.

These assets are not measured at fair value on an ongoing basis but are subject to fair value adjustments in certain circumstances.

Our proved natural gas and oil properties are reviewed for impairment periodically as events or changes in circumstances indicate the carrying amount may not be recoverable.

In first quarter 2020, we recognized impairment charges of $ 77.0 million that reduced the carrying value to the anticipated sales proceeds for our North Louisiana assets which is a market approach using Level 2 inputs.

These assets were sold in third quarter 2020.

In conjunction with the sale of our North Louisiana assets in third quarter 2020, we recorded impairment expense associated with our headquarters office lease of $ 2.0 million.

There were no proved property impairment charges in third quarter or first nine months 2021.

For first quarter 2022, interest and dividends were $ 115,000 and the mark-to-market adjustment was a loss of $ 4.3 million compared to interest and dividends of $ 109,000 and a mark-to-market gain of $ 2.0 million in first quarter 2021.

Fair Values –

The following presents the carrying amounts and the fair values of our financial instruments as of September 30, 2021 and December 31, 2020 (in thousands):

September 30, 2021

The following presents the carrying amounts and the fair values of our financial instruments as of March 31, 2022 and December 31, 2021 (in thousands):

March 31, 2022

December 31, 2021

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5.00 % senior notes due 2023 (b)

Other senior notes due 2022 (b)

4.875 % senior notes due 2025 (b)

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4.75 % senior notes due 2030 (b)

5.75 % senior subordinated notes due 2021 (b)

5.00 % senior subordinated notes due 2022 (b)

5.00 % senior subordinated notes due 2023 (b)

Deferred compensation plan (c)

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The book value of our bank debt approximates fair value because of its floating rate structure.

The fair value of our senior notes and our senior subordinated notes is based on end of period market quotes which are Level 2 inputs.

The fair value of our senior notes is based on end of period market quotes which are Level 2 inputs.

The fair value of our deferred compensation plan is updated to the closing price on the balance sheet date which is a Level 1 input.

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Concentrations of Credit Risk

As of September 30, 2021, our primary concentrations of credit risk are the risks of not collecting accounts receivable and the risk of a counterparty’s failure to perform under derivative obligations.

As of March 31, 2022, our primary concentrations of credit risk are the risks of not collecting accounts receivable and the risk of a counterparty’s failure to perform under derivative obligations.

Most of our receivables are from a diverse group of companies, including major energy companies, pipeline companies, local distribution companies, financial institutions and end-users in various industries.

Letters of credit or other appropriate assurances are obtained as deemed necessary to limit our risk of loss.

Our allowance for uncollectable receivables was $ 373,000 at September 30, 2021 compared to $ 3.0 million at December 31, 2020.

Our allowance for uncollectable receivables was $ 568,000 at both March 31, 2022 and December 31, 2021.

Our derivative exposure to credit risk is diversified primarily among major investment grade financial institutions, where we have master netting agreements which provide for offsetting payables against receivables from separate derivative contracts.

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We may also limit the level of exposure with any single counterparty.

At September 30, 2021, our derivative counterparties include nineteen financial institutions, of which all but five are secured lenders in our bank credit facility.

At September 30, 2021, our net derivative liability includes a net

receivable of $ 2.4 million from four of these counterparties that are not participants in our bank credit facility and an aggregate net payable of $ 9.2 million to one of these counterparties.

At March 31, 2022, our derivative counterparties include fifteen financial institutions, of which all but five are secured lenders in our bank credit facility.

At March 31, 2022, our net derivative liability includes a net receivable of $ 3.6 million from three of these counterparties that are not participants in our bank credit facility and an aggregate net payable of $ 1.6 million to two of these counterparties.

Allowance for Expected Credit Losses.

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Three Months Ended

September 30,

Nine Months Ended

September 30,

Direct operating expense

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General and administrative expense

Termination costs

Total stock-based compensation expense

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We grant three types of performance share awards:

two based on internal performance conditions which were initially measured against internal debt-adjusted performance metrics (Production Per Share Awards or PS-PSUs and Reserves Per Share Awards or RS-PSUs) and one based on market conditions measured based on Range’s performance relative to a predetermined peer group (TSR Awards or TSR-PSUs).

two based on internal performance conditions which are measured against internal performance metrics and one based on market conditions measured based on Range’s performance relative to a predetermined peer group (TSR Awards or TSR-PSUs).

In first quarter 2021, our internal performance metrics were changed to focus on debt reduction and to include an environmental component.

For shares granted in first quarter 2021, the performance conditions will be measured against internal metrics of Debt/EBITDAX (earnings before

interest, taxes, depreciation, amortization and exploration expense) and emission intensity performance.

These shares will vest at the end of three years and the three-year performance target was set in first quarter 2021.

For shares granted in 2021, the performance conditions will be measured against internal metrics of Debt/EBITDAX (earnings before interest, taxes, depreciation, amortization and exploration expense) and emission intensity performance.

In first quarter 2022, the performance conditions will be measured against internal metrics of net debt (total debt less cash on hand) and emission intensity performance.

Each unit granted represents one share of our common stock.

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Dividend equivalents may accrue during the performance period and are paid in stock at the end of the performance period.

The performance period for the TSR-PSUs is three years .

Prior to 2021, the performance period for the PS/RS-PSUs was based on annual performance targets earned over a three-year period.

The performance period is for three years .

Prior to 2021, the performance period for the internal performance metrics was based on annual performance targets earned over a three-year period.

Restricted Stock –

Equity Awards

In first nine months 2021, we granted 2.3 million restricted stock Equity Awards to employees at an average grant date fair value of $ 10.20 which generally vest over a three-year period compared to 4.5 million at an average grant date fair value of $ 3.42 in first nine months 2020.

We recorded compensation expense for these outstanding awards of $ 15.0 million in first nine months 2021 compared to $ 13.4 million in the same period of 2020.

In first three months 2022, we granted 1.4 million restricted stock Equity Awards to employees at an average grant date fair value of $ 18.47 which generally vest over a three-year period compared to 2.3 million at an average grant date fair value of $ 10.20 in first three months 2021.

We recorded compensation expense for these outstanding awards of $ 5.9 million in first three months 2022 compared to $ 5.2 million in the same period of 2021.

Restricted stock Equity Awards are not issued to employees until such time as they are vested.

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Liability Awards

In first nine months 2021, we granted 1.2 million shares of restricted stock Liability Awards as compensation to employees at an average grant date fair value of $ 9.30 which generally vest at the end of a three-year period and 102,000 shares were granted to non-employee directors at an average price of $ 12.49 with vesting at the end of a one-year period.

In first nine months 2020, we granted 3.3 million shares of restricted stock Liability Awards as compensation to employees at an average grant date fair value of $ 3.03 with vesting generally over a three-year period and 217,000 were granted to non-employee directors at an average price of $ 5.38 with vesting at the end of a one-year period.

We recorded compensation expense for these Liability Awards of $ 8.4 million in first nine months 2021 compared to $ 7.9 million in first nine months 2020.

In first three months 2022, we granted 602,000 shares of restricted stock Liability Awards as compensation to employees at an average grant date fair value of $ 20.42 which generally vest at the end of a three-year period.

In first three months 2021, we granted 1.2 million shares of restricted stock Liability Awards as compensation to employees at an average grant date fair value of $ 9.29 with vesting generally at the end of a three-year period.

We recorded compensation expense for these Liability Awards of $ 3.6 million in first three months 2022 compared to $ 2.9 million in first three months 2021.

The majority of these awards are held in our deferred compensation plan, are classified as a liability and are remeasured at fair value each reporting period.

This mark-to-market amount is reported as deferred compensation expense in our consolidated statements of operations (see additional discussion below).

The following is a summary of the status of our non-vested restricted stock outstanding at September 30, 2021:

The following is a summary of the status of our non-vested restricted stock outstanding at March 31, 2022:

Restricted Stock

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Outstanding at December 31, 2021

Outstanding at September 30, 2021

Outstanding at March 31, 2022

Stock-Based Performance Units

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If the performance metric for the applicable period is not met, that portion is considered forfeited and there is an adjustment to the expense recorded.

See additional information above for shares granted in first quarter 2021.

The following is a summary of our non-vested internal performance awards outstanding at September 30, 2021:

See additional information above for shares granted in first quarter 2021 and 2022.

The following is a summary of our non-vested internal performance awards outstanding at March 31, 2022:

Average Grant

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Vested and issued (b)

Outstanding at September 30, 2021

Outstanding at March 31, 2022

Amounts granted reflect the number of performance units granted;

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Units granted in first quarter 2022 were to our CEO, CFO and COO only.

For certain of the PS-PSUs and RS-PSUs awards issued during 2018 the aggregate payout was approximately 137 % of target for the March 2018 grants with a positive performance adjustment of 290,140 shares.

We recorded compensation expense of $ 3.8 million in first nine months 2021 compared to expense of $ 2.3 million in first nine months 2020.

For the awards issued during 2019, the aggregate payout was approximately 116 % of target with a positive performance adjustment of 158,793 shares.

We recorded compensation expense of $ 1.7 million in first three months 2022 compared to expense of $ 740,000 in first three months 2021.

TSR-PSUs granted are earned, or not earned, based on the comparative performance of Range’s common stock measured against a predetermined group of companies in the peer group over a three-year performance period.

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The risk-free interest rate was based on the United States Treasury rate for a term commensurate with the life of the grant.

The following assumptions were used to estimate the fair value of TSR-PSUs granted during first nine months 2021 and 2020:

Nine Months Ended

September 30,

The following assumptions were used to estimate the fair value of TSR-PSUs granted during first three months 2022 and 2021:

Three Months Ended

Risk-free interest rate

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The following is a summary of our non-vested TSR-PSUs award activities:

Average Grant

Date Fair Value

Outstanding at December 31, 2021

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Vested and issued (b)

Outstanding at September 30, 2021

Outstanding at March 31, 2022

These amounts reflect the number of performance units granted.

The actual payout of shares may be between zero and 200 % of the performance units granted depending on the total shareholder return ranking compared to our peer companies at the vesting date.

Includes TSR-PSUs awards issued related to the 2018 performance period where the return on our common stock was negative and therefore, the performance multiple and actual payout was reduced to 100 %.

We recorded TSR-PSUs compensation expense of $ 1.9 million in first nine months 2021 compared to $ 1.9 million in the same period of 2020.

Includes TSR-PSUs awards granted in 2019 where the return on our common stock was 127 % and therefore, the performance multiple and actual payout was 183 %.

We recorded TSR-PSUs compensation expense of $ 773,000 in first three months 2022 compared to $ 595,000 in the same period of 2021.

Fair value is amortized over the performance period with no adjustment to the expense recorded for actual targets achieved.

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These benefits are not funded in advance and are provided up to age 65 or at the date they become eligible for Medicare, subject to various cost-sharing features.

There was approximately $ 90,000 of estimated prior service costs amortized from accumulated other comprehensive income into general and administrative expense in both the three months ended September 30, 2021 and 2020 and approximately $ 275,000 amortized in both the nine months ended September 30, 2021 and 2020.

There was approximately $ 70,000 of estimated prior service costs amortized from accumulated other comprehensive income into general and administrative expense in first quarter 2022 compared to approximately $ 90,000 in first quarter 2021.

Those employees that qualify for this retirement health care plan are required to provide reasonable notice of retirement and provide one year of service after an equity grant date to be fully vested in the grant.

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Our stock held in the Rabbi Trust is treated as a liability award as employees are allowed to take withdrawals from the Rabbi Trust either in cash or in Range stock.

reporting period by a charge or credit to deferred compensation plan expense on our consolidated statements of operations.

The liability for the vested portion of the stock held in the Rabbi Trust is reflected as deferred compensation liability in the accompanying consolidated balance sheets and is adjusted to fair value each reporting period by a charge or credit to deferred compensation plan expense on our consolidated statements of operations.

The assets of the Rabbi Trust, other than our common stock, are invested in marketable securities and reported at their market value as other assets in the accompanying consolidated balance sheets.

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Changes in the market value of the marketable securities and changes in the fair value of the deferred compensation plan liability are charged or credited to deferred compensation plan expense each quarter.

We recorded a mark-to-market loss of $ 34.3 million in third quarter 2021 compared to a mark-to-market loss of $ 6.2 million in third quarter 2020.

We recorded mark-to-market loss of $ 89.6 million in first nine months 2021 compared to a loss of $ 10.3 million in first nine months 2020.

The Rabbi Trust held 6.4 million shares ( 5.3 million of which were vested) of Range stock at September 30, 2021 compared to 6.1 million shares ( 5.0 million of which were vested) at December 31, 2020.

We recorded a mark-to-market loss of $ 73.3 million in first quarter 2022 compared to a mark-to-market loss of $ 19.8 million in first quarter 2021.

The Rabbi Trust held 6.7 million shares ( 5.6 million of which were vested) of Range stock at March 31, 2022 compared to 6.2 million shares ( 5.4 million of which were vested) at December 31, 2021.

(13) EXIT AND TERMINATION COSTS

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The estimated obligations are included in current and long-term divestiture contract obligation in our consolidated balance sheets.

In first nine months 2021, we recorded accretion expense of $ 36.6 million.

In second quarter 2021, we recorded a net favorable adjustment of $ 28.2 million to reduce this obligation due to a reduction of certain contractual payments compared to those originally estimated and a change to our estimated drilling plans of the buyer.

The estimated discounted divestiture contract obligation was $ 426.6 million at September 30, 2021.

In first three months 2022, we recorded accretion expense of $ 11.0 million compared to $ 13.0 million in the same period of the prior year.

The estimated discounted divestiture contract obligation was $ 398.9 million at March 31, 2022.

In second quarter 2020, we negotiated capacity releases on certain transportation pipelines in Pennsylvania effective May 31, 2020 and extending through the remainder of the contract.

We recorded termination costs of $ 10.4 million which represented the discounted present value of our remaining obligation to the third-party.

The estimated remaining discounted obligation for these transportation capacity releases as of September 30, 2021 was $ 7.9 million.

The estimated remaining discounted obligation for these transportation capacity releases as of March 31, 2022 was $ 6.8 million.

Termination Costs

In third quarter 2020, we completed the sale of our North Louisiana assets.

We recorded $ 2.5 million of severance costs and stock-based compensation expense associated with this sale.

In third quarter 2020, we also announced an additional reduction in our work force and recorded $ 3.7 million of severance costs and stock-based compensation expense related to this reduction in force.

In first quarter 2020, we completed the sale of our shallow legacy assets in northwestern Pennsylvania and we recorded $ 1.6 million of severance costs which is primarily related to the sale of these assets.

The following summarizes our exit and termination costs for the three and nine months ended September 30, 2021 and 2020 (in thousands):

The following summarizes our exit and termination costs for the three months ended March 31, 2022 and 2021 (in thousands):

Three Months Ended

September 30,

Nine Months Ended

September 30,

Severance costs

Transportation contract capacity releases (including

Transportation contract capacity releases

(accretion of discount)

Divestiture contract obligation (including accretion of

One-time minimum volume commitment contract

Stock-based compensation

The following details the accrued exit and termination cost liability activity for the nine months ended September 30, 2021 (in thousands):

Divestiture contract obligation (accretion of

The following details the accrued exit and termination cost liability activity for the three months ended March 31, 2022 (in thousands):

Balance at December 31, 2021

Accrued severance costs

Accretion of discount

Divestiture contract obligation - changes in estimate

Balance at September 30, 2021

Balance at March 31, 2022

Includes the divestiture contract obligation and the transportation contract capacity release obligation.

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The following is a schedule of changes in the number of common shares outstanding since the beginning of 2021:

September 30,

Beginning balance

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Stock Repurchase Program

In October 2019, our Board of Directors authorized a $ 100.0 million common stock repurchase program.

In 2019, the board of directors approved a stock purchase program to acquire up to $ 100.0 million of our outstanding stock.

In early 2022, board authorized an additional repurchase of up to $ 430.0 million of our outstanding common stock for an aggregate available amount at that time of $ 500.0 million.

Under this program, we may repurchase shares in open market transactions, from time to time, in accordance with applicable SEC rules and federal securities laws.

The following is a schedule of the change in treasury shares for the three and nine months ended September 30, 2021:

September 30,

In first quarter 2022, we repurchased 600,000 shares at an aggregate cost of $ 16.2 million.

The following is a schedule of the change in treasury shares for the three months ended March 31, 2022:

Beginning balance

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(15) SUPPLEMENTAL CASH FLOW INFORMATION

Nine Months Ended

September 30,

Three Months Ended

(in thousands)

Net cash provided from operating activities included:

Income taxes (paid) refunded from taxing authorities

Income taxes paid to taxing authorities

Interest paid

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Increase in asset retirement costs capitalized

Decrease in accrued capital expenditures

(Increase) decrease in accrued capital expenditures

(16) COMMITMENTS AND CONTINGENCIES

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We have incurred and will continue to incur capital, operating and remediation expenditures as a result of environmental laws and regulations.

As of September 30, 2021, liabilities for remediation were not material.

We are not aware of any environmental claims existing as of September 30, 2021 that have not been provided for or would otherwise have a material impact on our financial position or results of operations.

As of March 31, 2022, liabilities for remediation were not material.

We are not aware of any environmental claims existing as of March 31, 2022 that have not been provided for or would otherwise have a material impact on our financial position or results of operations.

Environmental liabilities normally involve estimates that are subject to revision until final resolution, settlement or remediation occurs.

On March 4, 2021 a punitive class action lawsuit was filed in the Western District of Pennsylvania in Case No.

On March 4, 2021 a putative class action lawsuit was filed in the Western District of Pennsylvania in Case No.

2:21-CV-301 (Jacobowitz v.

Range Resources Corporation et al.) in which the Plaintiff seeks to represent a class of Range stockholders who purchased or acquired stock from April 29, 2016 to February 10, 2021.

This lawsuit has been transferred to the U.S.

District Court for the Northern District of Texas (Fort Worth Division).

The lawsuit claims that Range misclassified certain wells as inactive rather than having plugged the wells and that such alleged misclassification affected the determination of our asset retirement obligation accrual.

The lawsuit claims that the disclosure of a $ 294,000 agreed penalty that we paid to the Pennsylvania Department of Environmental Protection (DEP) in connection with the DEP’s investigation of our application for inactive status for a small number of our wells which the DEP disclosed during market hours on February 10, 2021 was the basis for the Plaintiffs’

discovery of the alleged misrepresentations.

We maintain that the factual allegations and the claims made in the litigation are baseless;

there were no misrepresentations made and our asset retirement obligation was properly calculated.

We also maintain that the market fully absorbed the information disclosed by the DEP on February 10, 2021 and the stock price on that day did not decrease.

Given our view of the litigation as baseless, we plan to vigorously defend the litigation and moved for its dismissal.

( 18) SUSPENDED EXPLORATORY WELL COSTS

We capitalize exploratory well costs until a determination is made that the well has either found proved reserves or that it is impaired.

Capitalized exploratory well costs are presented in natural gas and oil properties in the accompanying consolidated balance sheets.

If an exploratory well is determined to be impaired, the well costs are charged to exploration expense in the accompanying consolidated statements of operations.

The following table reflects the changes in capitalized exploratory well costs for the nine months ended September 30, 2021 (in thousands):

Balance at beginning of period

Additions to capitalized exploratory well costs pending the

determination of proved reserves

Reclassifications to wells, facilities and equipment based on

determination of proved reserves

Capitalized exploratory well costs, charged to expense

Balance at end of period

Less exploratory well costs that have been capitalized for a period

of one year or less

Capitalized exploratory well costs that have been capitalized for a

period greater than one year

Range Resources Corporation et al.) in which the Plaintiff sought to represent a class of Range stockholders who purchased or acquired stock from April 29, 2016 to February 10, 2021.

This lawsuit had been transferred to the U.S.

District Court for the Northern District of Texas (Fort Worth Division) and claimed that Range misclassified certain wells as inactive rather than having plugged the wells and that such alleged misclassification affected the determination of our asset retirement obligation accrual.

On March 31, 2022, the court granted our motion to dismiss and each claim was dismissed with prejudice.

Plaintiffs have until May 2 to file an appeal of the March 31 ruling and dismissal.

Additionally, on January 20, 2022, a derivative action styled as Lewis v.

Ventura et al.

was filed under seal in the Northern District of Texas (Case No.

4-22CV-051-0) asserting similar allegations as the Jacobowitz matter.

We maintain the same views as to the merits of the Lewis matter as the Jacobowitz matter and we plan to vigorously defend this matter and seek its dismissal.

(17) Costs Incurred for Property Acquisition, Exploration and Development (a)

September 30,

(in thousands)

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In addition, we target funding our capital spending to at or below operating cash flow.

Our revenues, profitability and future growth depend substantially on prevailing prices for natural gas and NGLs and on our ability to economically find, develop, acquire, produce and market natural gas and NGLs reserves.

Our revenues, profitability and future growth depend substantially on prevailing prices for natural gas, NGLs and oil and on our ability to economically find, develop, acquire, produce and market these reserves.

Commodity prices have been and are expected to remain volatile.

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target capital spending at or below operating cash flow;

reduce emissions and target net zero direct greenhouse gas emissions by 2025;

reduce emissions and target net-zero Scope 1 and Scope 2 greenhouse gas emissions by year-end 2025;

achieve competitive returns on investments;

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We prepare our financial statements in conformity with U.S.

GAAP which requires us to make estimates and assumptions that affect our reported results of operations and the amount of our reported assets, liabilities and proved natural gas and NGLs reserves.

GAAP which requires us to make estimates and assumptions that affect our reported results of operations and the amount of our reported assets, liabilities and proved reserves.

We use the successful efforts method of accounting for our natural gas, NGLs and oil activities.

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the quantity of natural gas, NGLs and oil shown as proved reserves;

the amount of cash flows available for capital expenditures;

the amount of cash flows available for reinvestment;

our ability to borrow and raise additional capital.

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Prices for natural gas, NGLs and oil that we produce significantly impact our revenues and cash flows.

Prices for commodities, such as hydrocarbons, are inherently volatile and are affected by many factors outside of our control.

Natural gas and oil benchmarks increased in third quarter 2021 when compared to the same period in 2020 and also in the first nine months 2021 when compared to the same period in 2020.

As a result, we experienced increased price realizations.

NYMEX natural gas futures have shown improvements based on market expectations that gas supplies will be limited due to slower growth of associated gas related activity in oil basins combined with reduced activity in natural gas basins and growing demand for liquefied natural gas exports.

While the current outlook on natural gas prices is generally favorable, in the event further disruptions occur and continue for an extended period of time, our operations could be impacted, commodity prices could decline and our costs may increase.

Through the end of third quarter 2021, uncertainty continued related to how long it will take to return to a balanced oil and natural gas supply and demand environment.

Other factors such as the duration of the COVID-19 pandemic and the speed and effectiveness of vaccine distributions or other medical advances to combat the virus

are expected to directly impact the recovery of world economic growth and the demand for oil, natural gas and NGLs.

As we continue to monitor the impact of the actions of OPEC and other large producing nations and the uncertainty associated with governmental policies aimed at redirecting fossil fuel consumption towards lower carbon energy, we expect prices for some or all of the commodities we produce to remain volatile.

The following table lists related benchmarks for natural gas, oil and NGLs composite prices for the three and nine months ended September 30, 2021 and 2020:

Natural gas, NGLs and oil benchmarks increased in first quarter 2022 when compared to the same period of 2021 and, as a result, we experienced a significant increase in price realizations.

As we continue to monitor the impact of the actions of OPEC and other large producing nations, the Russia-Ukraine conflict, global inventories of oil and gas and the uncertainty associated with recovering oil demand, future monetary policy and governmental policies aimed at transitioning towards lower carbon energy, we expect prices for some or all of the commodities we produce to remain volatile.

NYMEX natural gas futures have shown strong improvements based on market expectations that associated gas-related activity in oil basins and dry gas basin activity will show modest rates of growth compared with the past due to capital discipline, core inventory exhaustion and infrastructure constraints.

In addition, the global energy crisis further highlighted the low cost and low emissions shale gas resource base in North America, supporting continued strong structural demand growth for U.S.

LNG exports and domestic industrial gas demand.

Other factors such as the duration of the COVID-19 pandemic and the speed and effectiveness of vaccine distributions

or other medical advances to combat the virus may impact the recovery of world economic growth and the demand for oil, natural gas and NGLs.

The following table lists related benchmarks for natural gas, oil and NGLs composite prices for the three months ended March 31, 2022 and 2021:

Three Months Ended

September 30,

Nine Months Ended

September 30,

Average NYMEX prices (a)

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Consolidated Results of Operations

Overview of Third Quarter 2021 Results

For third quarter 2021, we experienced an increase in revenue from the sale of natural gas, NGLs and oil due to a 102% increase in net realized prices (average prices including all derivative settlements and third-party transportation costs paid by us) somewhat offset by lower production volumes when compared to the same quarter of 2020.

Daily production averaged 2.1 Bcfe in third quarter 2021 compared to 2.2 Bcfe in the same period of the prior year which is lower primarily due to the sale of our North Louisiana properties in third quarter 2020.

During third quarter 2021, we recognized a net loss of $350.3 million, or $1.44 per diluted common share compared to a net loss of $748.8 million, or $3.12 per diluted common share, during third quarter 2020.

The improvement in our net loss for third quarter 2021 compared to the third quarter 2020 includes significantly higher realized prices and lower divestiture contract obligation expenses offset by an increase in derivative fair value loss (or the non-cash fair value adjustment related to our derivatives) due to higher commodity prices and higher deferred compensation expense.

Our third quarter 2021 financial and operating performance included the following results:

reduced debt by $91.0 million with cash flow from operations;

cash flow from operating activities increased $216.1 million from third quarter 2020;

revenue from the sale of natural gas, NGLs and oil increased 123% from the same period of 2020 with a 129% increase in average realized prices (before cash settlements on our derivatives) partially offset by lower production volumes;

Overview of First Quarter 2022 Results

For first quarter 2022, we experienced an increase in revenue from the sale of natural gas, NGLs and oil due to a 108% increase in net realized prices (average prices including all derivative settlements and third-party transportation costs paid by us) somewhat offset by slightly lower production volumes when compared to the same quarter of 2021.

Daily production averaged 2.1 Bcfe in both the first quarter 2022 and 2021.Given the significant increase in commodity prices, our derivative fair value loss, which includes the non-cash fair value adjustment related to our derivatives, was $939.1 million compared to $57.9 million in the same quarter of the prior year.

For additional information on our derivative fair value loss, see page 30.

During first quarter 2022, we recognized a net loss of $456.8 million, or $1.86 per diluted common share compared to a net income of $27.2 million, or $0.11 per diluted common share during first quarter 2021.

The lower net income in first quarter 2022 compared to first quarter 2021 includes significantly higher derivative fair value loss (or the non-cash fair value adjustment related to our derivatives) due to higher commodity prices, higher deferred compensation expense and a loss on early extinguishment of debt partially offset by higher natural gas, NGLs and oil sales also due to higher commodity prices.

Our first quarter 2022 financial and operating performance included the following results:

reduced total debt by $350.0 million with cash on hand and cash flow;

reduced future interest expense through debt reduction combined with refinancing a portion of 9.25% senior notes due 2026 with 4.75% senior notes due 2030;

cash flow from operating activities increased $297.2 million from first quarter 2021;

ended the first quarter 2022 with $112.9 million of cash on hand;

revenue from the sale of natural gas, NGLs and oil increased 71% from the same period of 2021 with a 72% increase in average realized prices (before cash settlements on our derivatives) partially offset by slightly lower production volumes;

revenue from the sale of natural gas, NGLs and oil (including cash settlements on our derivatives) increased 59% from the same period of 2021;

direct operating expense per mcfe was $0.10 in both third quarter 2021 and 2020;

general and administrative expense per mcfe increased 32% from same quarter 2020 primarily due to higher legal settlements;

direct operating expense per mcfe was $0.11 in first quarter 2022 compared to $0.09 in the same period of 2021 due to higher water handling and higher contract labor and service costs;

general and administrative expense per mcfe increased 15% from same quarter 2021 primarily due to higher stock-based compensation and higher salaries and benefits;

reduced depletion, depreciation and amortization (“DD&A”) rate per mcfe by 2% from the same period of 2021.

Our cash flow from operating activities in third quarter 2021 was $191.9 million, an increase of $216.1 million from third quarter 2020 with significantly higher realized prices when compared to third quarter 2020 partially offset by slightly lower production volumes.

Cash flow from operating activities was also favorably impacted by lower net cash outflow from working capital.

Overview of First Nine Months 2021 Results

For first nine months 2021, we experienced an increase in revenue from the sale of natural gas, NGLs and oil due to a 68% increase in net realized prices (average prices including all derivatives settlements and third-party transportation costs

paid by us) somewhat offset by lower production volumes when compared to the same period of 2020.

Daily production averaged 2.1 Bcfe in first nine months 2021 compared to 2.3 Bcfe in the same period of the prior year due to the sale of our North Louisiana properties in third quarter 2020.

In addition, direct operating costs were lower when compared to the same period of 2020.

During first nine months 2021, we recognized a net loss of $479.6 million, or $1.98 per diluted common share compared to a net loss of $750.2 million, or $3.10 per diluted common share, during the same period of 2020.

The improvement in our net loss for first nine months 2021 from first nine months 2020 is primarily due to significantly higher realized prices, lower proved property impairment and lower divestiture contract obligation expenses partially offset by an increase in derivative fair value loss (or the non-cash fair value adjustment related to our derivatives) and a lower gain on asset sales and higher deferred compensation plan expenses.

Our first nine months financial and operating performance included the following results:

reduced debt by $135.3 million with cash flow from operations;

cash flow from operating activities increased 166% from the same period of 2020;

revenue from the sale of natural gas, NGLs and oil increased 78% from the same period of 2020 with a 94% increase in average realized prices (before cash settlements on our derivatives) partially offset by lower production volumes;

revenue from the sale of natural gas, NGLs and oil (including settlements on our derivatives) increased 25% from the same period of 2020;

direct operating expense per mcfe was 17% lower than the same period of 2020 (see discussion on page 34);

general and administrative expense per mcfe increased 16% from first nine months 2020 due to higher legal expenses and legal settlements (see discussion on page 34);

reduced DD&A rate per mcfe by 4%, or $31.7 million from the same period of 2020;

issued $600.0 million of new senior notes and used the proceeds to reduce our bank credit facility borrowing.

Our cash flow from operating activities in first nine months 2021 was $475.3 million, an increase of $296.3 million from first nine months 2020.

First nine months 2021 cash flow from operating activities included significantly higher realized prices and lower net operating costs partially offset by the impact of negative working capital due to higher commodity prices.

Our cash flow from operating activities in first quarter 2022 was $406.4 million, an increase of $297.2 million from first quarter 2021 with significantly higher realized prices when compared to first quarter 2021 partially offset by slightly lower production volumes.

Natural Gas, NGLs and Oil Sales, Production and Realized Price Calculations

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Our revenues are generally recognized when control of the product is transferred to the customer and collectability is reasonably assured.

In third quarter 2021, natural gas, NGLs and oil sales increased 123% compared to third quarter 2020 with a 129% increase in average realized prices (before cash settlements on our derivatives) partially offset by a 3% reduction in production volumes.

In first nine months 2021, natural gas, NGLs and oil sales increased 78% compared to first nine months 2020 with a 94% increase in average realized prices partially offset by a 8% reduction in production volumes.

The following table illustrates the primary components of natural gas, NGLs, oil and condensate sales for the three and nine months ended September 30, 2021 and 2020 (in thousands):

In first quarter 2022, natural gas, NGLs and oil sales increased 71% compared to first quarter 2021 with a 72% increase in average realized prices (before cash settlements on our derivatives) partially offset by a 1% reduction in production volumes.

The following table illustrates the primary components of natural gas, NGLs and oil sales for the three months ended March 31, 2022 and 2021 (in thousands):

Three Months Ended

September 30,

Nine Months Ended

September 30,

Natural gas, NGLs and oil sales

Total natural gas, NGLs and oil sales

Our production is determined by drilling success which offsets the natural decline of our natural gas and oil reserves through production and asset sales.

Third quarter 2020 production volumes from our North Louisiana properties were approximately 72.5 Mmcfe per day and were 139.0 mcfe per day for first nine months 2020.

These assets were sold in third quarter 2020.

Our production for the three and nine months ended September 30, 2021 and 2020 is set forth in the following table:

Our production is determined by drilling success which offsets the natural decline of our natural gas and oil reserves through production.

Our production for the three months ended March 31, 2022 and 2021 is set forth in the following table:

Three Months Ended

September 30,

Nine Months Ended

September 30,

Production (a)

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Oil and NGLs volumes are converted to mcfe at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil to natural gas, which is not indicative of the relationship between oil and natural gas prices.

Our average realized price received (including all derivative settlements and third-party transportation costs) during third quarter 2021 was $2.00 per mcfe compared to $0.99 per mcfe in third quarter 2020.

Our average realized price received (including all derivative settlements and third-party transportation costs) during first nine months 2021 was $1.71 per mcfe compared to $1.02 per mcfe in first nine months 2020.

Our average realized price received (including all derivative settlements and third-party transportation costs) during first quarter 2022 was $3.23 per mcfe compared to $1.55 per mcfe in first quarter 2021.

We believe computed final realized prices should include the total impact of transportation, gathering, processing and compression expense.

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Average realized prices (excluding derivative settlements) do include transportation costs where we receive net revenue proceeds from purchasers.

Average realized price calculations for three and nine months ended September 30, 2021 and 2020 are shown below:

Average realized price calculations for three months ended March 31, 2022 and 2021 are shown below:

Three Months Ended

September 30,

Nine Months Ended

September 30,

Average Prices

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Three Months Ended

September 30,

Nine Months Ended

September 30,

Average natural gas differentials below NYMEX

Realized gains on basis hedging

Realized gains (losses) on basis hedging

The following tables reflect our production and average realized commodity prices (excluding derivative settlements and third-party transportation costs paid by Range) (in thousands, except prices):

Three Months Ended

September 30,

Nine Months Ended

September 30,

Price (per mcf)

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Three Months Ended

September 30,

Nine Months Ended

September 30,

Price (per bbl)

1 unchanged sentence

Three Months Ended

September 30,

Nine Months Ended

September 30,

Price (per bbl)

2 unchanged sentences

Three Months Ended

September 30,

Nine Months Ended

September 30,

Price (per mcfe)

Production (Mmcfe)

Total natural gas, NGLs and oil

Transportation, gathering, processing and compression expense was $296.5 million in third quarter 2021 compared to $268.1 million in third quarter 2020.

These third-party costs are higher in third quarter 2021 when compared to third quarter 2020 due to the impact of higher NGLs prices which result in higher processing costs, higher fuel costs and higher gathering costs partially offset by the impact of the sale of our North Louisiana assets in third quarter 2020.

Transportation, gathering, processing and compression expense was $853.7 million in first nine months 2021 compared to $831.7 million in first nine months 2020.

These third-party costs are higher when compared to the same period of the prior year due to the impact of higher NGLs prices which results in higher processing costs and higher fuel costs somewhat offset by the impact of the sale of our North Louisiana assets in third quarter 2020 and transportation capacity released in Pennsylvania.

Total natural gas,

NGLs and oil sales

Transportation, gathering, processing and compression expense was $297.8 million in first quarter 2022 compared to $274.3 million in first quarter 2021.

These third-party costs are higher in first quarter 2022 when compared to first quarter 2021 due to the impact of higher NGLs prices which results in higher processing costs.

We have included these costs in the calculation of average realized prices (including all derivative settlements and third-party transportation expenses paid by Range).

The following table summarizes transportation, gathering, processing and compression expense for the three and nine months ended September 30, 2021 and 2020 on a per mcf and per barrel basis (in thousands, except for costs per unit):

The following table summarizes transportation, gathering, processing and compression expense for the three months ended March 31, 2022 and 2021 on a per mcf and per barrel basis (in thousands, except for costs per unit):

Three Months Ended

September 30,

Nine Months Ended

September 30,

Transportation, gathering,

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Oil (per bbl)

Derivative fair value (loss) income was a loss of $652.2 million in third quarter 2021 compared to a loss of $124.7 million in third quarter 2020.

Derivative fair value loss was $959.8 million in first nine months 2021 compared to income of $102.2 million in first nine months 2020.

Derivative fair value loss was $939.1 million in first quarter 2022 compared to $57.9 million in first quarter 2021.

All of our derivatives are accounted for using the mark-to-market accounting method.

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Gains on our derivatives generally indicate potentially lower wellhead revenues in the future while losses indicate potentially higher future wellhead revenues.

The following table summarizes the impact of our commodity derivatives for three months and nine months ended September 30, 2021 and 2020 (in thousands):

The following table summarizes the impact of our commodity derivatives for three months ended March 31, 2022 and 2021 (in thousands):

Three Months Ended

September 30,

Nine Months Ended

September 30,

Derivative fair value (loss) income per consolidated statements of

Derivative fair value loss per consolidated statements of

Non-cash fair value (loss) gain:

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Total non-cash fair value (loss) gain (1)

Net cash (payment) receipt on derivative settlements:

Net cash payment on derivative settlements:

Natural gas derivatives

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NGLs derivatives

Total net cash (payment) receipt

Total net cash payment

Non-cash fair value adjustments on commodity derivatives is a non-U.S.

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This also includes the change in fair value of our divestiture contingent consideration.

Brokered natural gas, marketing and other revenue in third quarter 2021 was $105.6 million compared to $42.5 million in third quarter 2020 which is the result of significantly higher broker sales prices and higher broker sales volumes (volumes not related to our production).

Brokered natural gas, marketing and other revenue in first nine months 2021 was $248.7 million compared to $104.7 million in first nine months 2020 which is the result of significantly higher broker sales prices, slightly higher broker sales volumes and $8.8 million received as part of a capacity release agreement.

Brokered natural gas, marketing and other revenue in first quarter 2022 was $87.4 million compared to $80.6 million in first quarter 2021 which is the result of significantly higher broker sales prices somewhat offset by lower broker sales volumes (volumes not related to our production).

First quarter 2021 also includes $8.8 million received as part of a capacity release agreement.

We continue to optimize our transportation portfolio using these volumes.

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We believe some of our expense fluctuations are best analyzed on a unit-of-production or per mcfe basis.

The following table presents information about certain of our expenses on a per mcfe basis for the three and nine months ended September 30, 2021 and 2020:

The following table presents information about certain of our expenses on a per mcfe basis for the three months ended March 31, 2022 and 2021:

Three Months Ended

September 30,

Nine Months Ended

September 30,

Direct operating expense

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Depletion, depreciation and amortization expense

Direct operating expense was $20.2 million in third quarter 2021 compared to $19.5 million in third quarter 2020.

Direct operating expense was $20.3 million in first quarter 2022 compared to $17.7 million in first quarter 2021.

Direct operating expenses include normally recurring expenses to operate and produce our wells, non-recurring well workovers and repair-related expenses.

Our direct operating costs increased in third quarter 2021 primarily due to higher water handling/hauling costs and higher stock-based compensation partially offset by the impact of the sale of our North Louisiana properties.

Our production volumes decreased 3% in third quarter 2021.

We incurred $896,000 of workover costs in third quarter 2021 compared to $856,000 in third quarter 2020.

On a per mcfe basis, direct operating expense in both third quarter 2021 and 2020 was $0.10.

Direct operating expense was $57.7 million in first nine months 2021 compared to $75.9 million in the same period 2020.

Our direct operating expenses decreased in first nine months 2021 compared to the same period of the prior year due to the impact of the sale of our higher cost North Louisiana properties in third quarter 2020 and lower workover costs partially offset by higher water handling/hauling costs.

Our production volumes decreased 8% in first nine months 2021.

We incurred $3.3 million of workover costs in first nine months 2021 compared to $6.4 million in first nine months 2020.

On a per mcfe basis, direct operating costs decreased 17% from $0.12 to $0.10 with the decrease due to the impact of the sale of our higher cost North Louisiana properties.

The following table summarizes direct operating expense per mcfe for the three and nine months ended September 30, 2021 and 2020:

Our direct operating costs increased in first quarter 2022 primarily due to higher water handling/hauling costs, higher contract labor and services and higher workover costs.

Our production volumes decreased 1% in first quarter 2022.

We incurred $881,000 of workover costs in first quarter 2022 compared to $659,000 in first quarter 2021.

On a per mcfe basis, direct operating expense was $0.11 in first quarter 2022 compared to $0.09 in the same quarter of the prior year due to higher water handling/hauling costs and higher contract labor and services.

The following table summarizes direct operating expense per mcfe for the three months ended March 31, 2022 and 2021:

Three Months Ended

September 30,

Nine Months Ended

September 30,

Direct operating

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which functions as a tax on unconventional natural gas and oil production from the Marcellus Shale in Pennsylvania.

This impact fee was $7.1 million in third quarter 2021 compared to $4.5 million in third quarter 2020 due to higher natural gas prices partially offset by the mix of wells relative to the impact fee structure where the fee declines over time.

In second quarter, we adjusted our impact fee accrual for the six months 2021 to reflect the impact higher natural gas prices have on impact fee rates.

These rates are based on benchmark natural gas prices.

Production and ad valorem taxes (excluding the impact fee) were $13,000 in third quarter 2021 compared to $1.6 million in second quarter 2020 with the decrease due to the impact of the sale of our North Louisiana assets.

Included in first nine months 2021 is a $20.1 million impact fee compared to $13.3 million in first nine months 2020 with the increase due to higher natural gas prices.

Production and ad valorem taxes (excluding the impact fee) were $32,000 in first nine months 2021 compared to $7.4 million in first nine months 2020 with the decrease due to the impact of the sale of our North Louisiana assets.

The following table summarizes production and ad valorem taxes per mcfe for the three and nine months ended September 30, 2021 and 2020:

This impact fee was $6.6 million in first quarter 2022 compared to $4.6 million in first quarter 2021 due to higher natural gas prices partially offset by the mix of wells relative to the impact fee structure where the fee declines over time.

The following table summarizes production and ad valorem taxes per mcfe for the three months ended March 31, 2022 and 2021:

Three Months Ended

September 30,

Nine Months Ended

September 30,

Production and ad valorem taxes

1 unchanged sentence

Total production and ad valorem taxes

General and administrative (G&A) expense was $49.1 million in third quarter 2021 compared to $38.2 million in third quarter 2020.

The third quarter 2021 increase of $10.9 million when compared to the same period of 2020 is primarily due to higher accrual for legal settlements of $7.2 million, higher stock-based compensation and higher general office expenses partially offset by lower salaries and benefits.

At September 30, 2021, the number of G&A employees decreased 7% when compared to September 30, 2020.

On a per mcfe basis, third quarter 2021 G&A expense was 32% higher than third quarter 2020 due to higher legal settlements and higher stock-based compensation expenses.

G&A expense for first nine months 2021 increased $8.6 million when compared to the same period 2020 due to higher legal expenses and legal settlements of $7.5 million, higher stock-based compensation and higher general office expenses somewhat offset by lower salaries and benefits.

On a per mcfe basis, first nine months 2021 G&A expense increased 16% from

first nine months 2020 due to higher legal expenses and legal settlements, higher stock-based compensation and the impact of lower production volumes.

The following table summarizes G&A expenses on a per mcfe basis for the three and nine months ended September 30, 2021 and 2020:

General and administrative (G&A) expense was $43.0 million in first quarter 2022 compared to $38.0 million in first quarter 2021.

The first quarter 2022 increase of $5.0 million when compared to the same period of 2021 is primarily due to higher stock-based compensation expense of $2.2 million, higher general office expenses including technology costs and higher salaries and benefits.

At March 31, 2022, the number of G&A employees decreased 1% when compared to March 31, 2021.

On a per mcfe basis, first quarter 2022 G&A expense was 15% higher than first quarter 2021 due to higher stock-based compensation expense, higher general office expenses and higher salaries and benefits.

The following table summarizes G&A expenses on a per mcfe basis for the three months ended March 31, 2022 and 2021:

Three Months Ended

September 30,

Nine Months Ended

September 30,

General and administrative

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Total general and administrative expense

Interest expense was $56.8 million in third quarter 2021 compared to $48.0 million in third quarter 2020.

Interest expense was $171.0 million for first nine months 2021 compared to $144.1 million for first nine months 2020.

The following table presents information about interest expense per mcfe for the three and nine months ended September 30, 2021 and 2020:

Interest expense was $47.2 million in first quarter 2022 compared to $56.9 million in first quarter 2021.

The following table presents information about interest expense per mcfe for the three months ended March 31, 2022 and 2021:

Three Months Ended

September 30,

Nine Months Ended

September 30,

Bank credit facility

4 unchanged sentences

Includes commitment fees but excludes debt issue costs and amortization of discounts and premiums.

On an absolute basis, the increase in interest expense for third quarter 2021 from the same period of 2020 was primarily due to higher average interest rates partially offset by slightly lower overall average outstanding debt balances.

Average debt outstanding on the bank credit facility for third quarter 2021 was $139.0 million compared to $684.6 million in third quarter 2020 and the weighted average interest rate on the bank credit facility was 2.0% in third quarter 2021 compared to 2.4% in third quarter 2020.

On an absolute basis, the increase in interest expense for first nine months 2021 from the same period 2020 was primarily due to higher average interest rates partially offset by slightly lower overall average outstanding debt balances.

Average debt outstanding on the bank credit facility was $185.0 million for first nine months 2021 compared to $628.6 million for first nine months 2020 and the weighted average interest rates on the bank credit facility were 2.1% in first nine months 2021 compared to 2.7% in first nine months 2020.

Depletion, depreciation and amortization expense was $93.1 million in third quarter 2021 compared to $96.2 million in third quarter 2020.

On an absolute basis, the decrease in interest expense for first quarter 2022 from the same period of 2021 was primarily due to lower overall average interest rates and lower average outstanding debt balances.

Average debt outstanding on the bank credit facility for first quarter 2022 was $65.3 million compared to $220.4 million in first quarter 2021 and the weighted average interest rate on the bank credit facility was 2.5% in first quarter 2022 compared to 2.2% in first quarter 2021.

Depletion, depreciation and amortization expense was $85.6 million in first quarter 2022 compared to $88.4 million in first quarter 2021.

This decrease is due to a 2% decrease in depletion rates and a 1% decrease in production volumes.

Depletion expense, the largest component of DD&A expense, was $0.46 per mcfe in third quarter 2021 compared to $0.47 per mcfe in third quarter 2020.

Depletion expense, the largest component of DD&A expense, was $0.45 per mcfe in first quarter 2022 compared to $0.46 per mcfe in first quarter 2021.

We have historically adjusted our depletion rates in the fourth quarter of each year based on the year-end reserve report and at other times during the year when circumstances indicate there has been a significant change in reserves or costs.

Our depletion rate per mcfe continues to decline due to asset sales and the mix of production from our properties with lower depletion rates.

DD&A expense was $272.1 million in first nine months 2021 compared to $303.8 million in the same period of 2020.

This is due to a 4% decrease in depletion rates and a 8% decrease in production volumes.

Depletion expense per mcfe was $0.46 per mcfe in first nine months 2021 compared to $0.48 per mcfe in the same period of 2020.

The following table summarizes DD&A expense per mcfe for the three and nine months ended September 30, 2021 and 2020:

The following table summarizes DD&A expense per mcfe for the three months ended March 31, 2022 and 2021:

Three Months Ended

September 30,

Nine Months Ended

September 30,

Depletion and amortization

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Our total operating expenses also include other expenses that generally do not trend with production.

These expenses include stock-based compensation, brokered natural gas and marketing expense, exploration expense, abandonment and impairment of unproved properties, exit and termination costs, deferred compensation plan expenses, loss or gain on early extinguishment of debt, impairment of proved properties and gain or loss on sale of assets.

Stock-based compensation includes the amortization of restricted stock grants and PSUs.

The following table details the allocation of stock-based compensation to functional expense categories for the three and nine months ended September 30, 2021 and 2020 (in thousands):

The following table details the allocation of stock-based compensation to functional expense categories for the three months ended March 31, 2022 and 2021 (in thousands):

Three Months Ended

September 30,

Nine Months Ended

September 30,

Direct operating expense

2 unchanged sentences

General and administrative expense

Termination costs

Total stock-based compensation

Brokered natural gas and marketing expense was $105.8 million in third quarter 2021 compared to $48.0 million in third quarter 2020 due to higher broker purchase volumes (volumes not related to our production) and significantly higher commodity prices.

Brokered natural gas and marketing expense was $247.2 million in first nine months 2021 compared to $118.8 million in first nine months 2020 due to significantly higher broker purchase volumes and significantly higher commodity prices.

The following table details our brokered natural gas, marketing and other net margin for the three and nine months ended September 30, 2021 and 2020 (in thousands):

Brokered natural gas and marketing expense was $93.1 million in first quarter 2022 compared to $72.3 million in first quarter 2021 due to higher commodity prices somewhat offset by lower broker purchase volumes (volumes not related to our production).

The following table details our brokered natural gas, marketing and other net margin for the three months ended March 31, 2022 and 2021 (in thousands):

Three Months Ended

September 30,

Nine Months Ended

September 30,

Brokered natural gas and marketing

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Net brokered natural gas and marketing margin

The three months ended March 31, 2021 includes $8.8 million received as part of a capacity release agreement.

Includes transportation costs.

Exploration expense was $5.9 million in third quarter 2021 compared to $8.1 million in third quarter 2020 due to lower delay rentals.

Exploration expense was $16.4 million in first nine months 2021 compared to $23.2 million in first nine months 2020 due to lower delay rentals and other expenses and lower personnel costs.

The following table details our exploration expense for the three and nine months ended September 30, 2021 and 2020 (in thousands):

Exploration expense was $4.7 million in first quarter 2022 compared to $5.5 million in first quarter 2021 due to lower delay rentals and other expense.

The following table details our exploration expense for the three months ended March 31, 2022 and 2021 (in thousands):

Three Months Ended

September 30,

Nine Months Ended

September 30,

Delay rentals and other

2 unchanged sentences

Total exploration expense

Abandonment and impairment of unproved properties was $2.0 million in third quarter 2021 compared to $5.7 million in third quarter 2020.

Abandonment and impairment of unproved properties was $7.2 million in first nine months 2021 compared to $16.6 million in first nine months 2020.

Abandonment and impairment of unproved properties for third quarter and first nine months 2021 declined when compared to the same periods of 2020 due to lower estimated expirations in Pennsylvania.

Exit and termination costs was $11.8 million in third quarter 2021 compared to $521.6 million in third quarter 2020.

In third quarter 2021, we recorded $11.8 million accretion expense primarily related to retained liabilities for certain gathering, transportation and processing obligations extending until 2030.

In third quarter 2020, we sold our North Louisiana assets and retained certain gathering, transportation and processing obligations which extend into 2030.

The fair value of our estimated obligations was recorded in third quarter 2020 and totaled $479.8 million.

In addition, as part of retaining these contract obligations, we paid $28.5 million to a midstream company to reduce these financial commitments.

In third quarter 2020, we also recorded $6.2 million of severance and stock-based compensation related to the sale of this asset along with an additional general reduction in our work force.

Exit and termination costs was $9.6 million in first nine months 2021 compared to $533.5 million in first nine months 2020.

In first nine months 2021, we recorded $37.2 million accretion expense related to these retained liabilities and in second quarter 2021, we recorded a gain of $28.2 million to reduce our original estimate of these retained obligations due to payments being lower than our forecast and a change in our forecasted drilling plans of the buyer.

In second quarter 2020, we also negotiated capacity releases on certain transportation pipelines in Pennsylvania and recorded termination costs of $10.4 million which represents the discounted present value of our remaining obligation to the third party.

Deferred compensation plan expense was a loss of $34.3 million in third quarter 2021 compared to a loss of $6.2 million in third quarter 2020.

Abandonment and impairment of unproved properties was $2.0 million in first quarter 2022 compared to $3.0 million in first quarter 2021.

Abandonment and impairment of unproved properties for first quarter declined when compared to the same periods of 2021 due to lower estimated expirations in Pennsylvania.

Exit and termination costs was $11.1 million in first quarter 2022 compared to $13.7 million in first quarter 2021.

In first quarter 2022, we recorded $11.1 million accretion expense primarily related to retained liabilities for certain gathering, transportation and processing obligations extending until 2030 compared to accretion expense of $13.2 million in the same quarter of the prior year.

Deferred compensation plan expense was a loss of $73.3 million in first quarter 2022 compared to a loss of $19.8 million in first quarter 2021.

This non-cash item relates to the increase or decrease in value of the liability associated with our common stock that is vested and held in our deferred compensation plan.

The deferred compensation liability is adjusted to fair value by a charge or a credit to deferred compensation plan expense.

Our stock price increased from $16.76 at June 30, 2021 to $22.63 at September 30, 2021.

In the same period of the prior year, our stock price increased from $5.63 at June 30, 2020 to $6.62 at September 30, 2020.

During first nine months 2021, deferred compensation was a loss of $89.6 million compared to a loss of $10.3 million in the same period of 2020.

Our stock price increased from $6.70 at December 31, 2020 to $22.63 at September 30, 2021.

In the same period of the prior year, our stock price increased from $4.85 at December 31, 2019 to $6.62 at September 30, 2020.

Loss (gain) on early extinguishment of debt was a loss of $7.8 million in third quarter 2020.

In third quarter 2020, we purchased for cash $500.0 million aggregate principal amount of various senior and senior subordinated notes due 2021, 2022 and 2023.

We recorded a loss on early extinguishment of debt of $8.0 million, net of transaction call premium costs and expensing the remaining deferred financing costs.

Loss on extinguishment of debt was a gain of $14.1 million in nine months 2020.

In second quarter 2020, we repurchased in the open market certain of our senior and senior subordinated notes at a discount and recognized a gain of $9.0 million.

In January 2020, we purchased for cash $500.0 million aggregate principal amount of our 5.75% senior notes due 2021 and our 5.875% senior notes due 2022.

An early cash tender of $15.1 million was paid to note holders who tendered their notes within the early offer period.

We recorded a loss on early extinguishment of debt in first quarter 2020 of $17.5 million, net of transaction call premium costs and the expenses of the remaining deferred financing costs on the repurchased debt.

The cash tender offer and early cash tender premium were financed from the issuance of our 9.25% senior notes.

Also in first quarter 2020, we purchased in the open market $48.5 million principal amount of our 5.00% senior notes due 2022, $5.8 million principal amount of our 5.875% senior notes due 2022 and $56.6 million principal amount of our 5.00% senior notes due 2023.

We recognized a gain on early extinguishment of debt in first quarter 2020 of $30.4 million, net of transaction costs and the expensing of the remaining deferred financing costs on the repurchased debt.

Impairment of proved properties and other assets was $79.0 million in first nine months 2020.

There were no proved property impairments in first nine months 2021.

In fourth quarter 2019, we recorded impairment expense related to our oil and gas properties in North Louisiana due to a shift in business strategy and the possibility of a divestiture of those assets.

In first quarter 2020, additional impairment of $77.0 million was recorded related to these North Louisiana assets based on market indications of fair value for these assets.

Loss (gain) on the sale of assets was a gain of $724,000 in first nine months 2021 compared to a gain of $112.4 million in the same period of 2020.

In first six months 2021, we recorded an additional gain on the sale of our North Louisiana assets of $479,000.

In third quarter 2020, we sold our North Louisiana assets and recorded a pretax loss of $8.1 million on this sale, after closing adjustments.

In first quarter 2020, we received approval from state governmental authorities for a change in operatorship for our shallow Northwest Pennsylvania properties and we recorded a gain on the sale of these legacy assets of $122.5 million.

We did retain the deeper Utica rights on this acreage as part of this transaction.

Income tax benefit was $29.7 million in third quarter 2021 compared to $36.5 million in third quarter 2020.

Income tax benefit was $28.3 million in first nine months 2021 compared to $29.8 million in first nine months 2020.

Our stock price increased from $17.83 at December 31, 2021 to $30.38 at March 31, 2022.

In the same period of the prior year, our stock price increased from $6.70 at December 31, 2020 to $10.33 at March 31, 2021.

Loss on early extinguishment of debt was a loss of $69.2 million in first quarter 2022 compared to a loss of $35,000 in the same period of the prior year.

In first quarter 2022, we announced a call for the redemption of $850.0 million of our outstanding 9.25% senior notes due 2026.

The redemption price equaled 106.938% of par plus accrued and unpaid interest.

We recognized a loss on early extinguishment of debt in first quarter 2022 of $69.2 million, net of transaction costs and the expensing of the remaining deferred financing costs on the repurchased debt.

Income tax (benefit) expense was a benefit of $116.1 million in first quarter 2022 compared to expense of $2.7 million in first quarter 2021.

The 2022 and 2021 effective tax rates were different than the statutory tax rate due to state income taxes, equity compensation, valuation allowances and other discrete tax items.

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Our cash flows from operations are also impacted by changes in working capital.

We generally maintain low cash and cash equivalent balances because we use available funds to reduce our bank debt.

Short-term liquidity needs are satisfied by borrowings under our bank credit facility.

Short-term liquidity needs are satisfied by borrowings under our bank credit facility and/or cash on hand.

Because of this, and because our principal source of operating cash flows (proved reserves to be produced in future years) cannot be reported as working capital, we often have low or negative working capital.

From time to time, we enter into various derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future natural gas, NGLs and oil production.

The production we hedge has varied and will continue to vary from year to year depending on, among other things, our expectation of future commodity prices.

The production we hedge has varied and will continue to vary from year to year depending on, among other things, our expectation of future commodity prices and capital requirements.

Any payments due to counterparties under our derivative contracts should ultimately be funded by prices received from the sale of our production.

Production receipts, however, often lag payments to the counterparties.

As of September 30, 2021, we have entered into derivative agreements covering 120.8 Bcfe for the remainder of 2021, 331.8 Bcfe for 2022 and 22.4 Bcfe for 2023, not including our basis swaps.

The following table presents sources and uses of cash and cash equivalents for the nine months ended September 30, 2021 and 2020 (in thousands):

Nine Months Ended

September 30,

As of March 31, 2022, we have entered into derivative agreements covering 295.9 Bcfe for the remainder of 2022, 246.6 Bcfe for 2023 and 73.2 Bcfe for 2024, not including our basis swaps.

The following table presents sources and uses of cash and cash equivalents for the three months ended March 31, 2022 and 2021 (in thousands):

Three Months Ended

Sources of cash and cash equivalents

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Sources of Cash and Cash Equivalents

Cash flows provided from operating activities in first nine months 2021 was $475.3 million compared to $179.0 million in first nine months 2020.

Cash flows provided from operating activities in first three months 2022 was $406.4 million compared to $109.3 million in first three months 2021.

Cash provided from operating activities is largely dependent upon commodity prices and production volumes, net of the effects of settlement of our derivative contracts.

The increase in cash provided from operating activities from first nine months 2020 to first nine months 2021 reflects higher realized prices and lower operating expenses partially offset by working capital cash outflow and lower production volumes.

As of September 30, 2021, we have hedged more than 65% of our projected total production for the remainder of 2021, with more than 75% of our projected natural gas production hedged.

The increase in cash provided from operating activities from first three months 2021 to first three months 2022 reflects higher realized prices partially offset by lower production volumes.

As of March 31, 2022, we have hedged more than 55% of our projected total production for the remainder of 2022, with more than 65% of our projected natural gas production hedged.

Net cash provided from operating activities was affected by a 1% decrease in production and working capital changes or the timing of cash receipts and disbursements.

Changes in working capital (as reflected in our consolidated statements of cash flows) for first nine months 2021 were negative $143.6 million compared to a negative $47.8 million for first nine months 2020.

Changes in working capital (as reflected in our consolidated statements of cash flows) for first three months 2022 were negative $77.4 million compared to a negative $77.3 million for first three months 2021.

Issuance of senior notes in first three months 2022 includes the issuance of $500.0 million new 4.75% senior notes due 2030.

Uses of Cash and Cash Equivalents

Additions to natural gas and oil properties for first nine months 2021 were consistent with expectations relative to our 2021 capital budget.

Repayment of senior and senior subordinated notes for first nine months 2021 includes the redemption of various senior and senior subordinated notes due 2021, 2022 and 2023.

The first nine months 2020 includes purchases in the open market various senior and senior subordinated notes due 2021, 2022 and 2023.

In addition, in conjunction with the issuance of our $850.0 million aggregate principal amount 9.25% senior notes due 2026, we used the proceeds from this issuance and the sale of our North Louisiana assets to redeem $336.2 million of our 5.75% senior notes due 2021 and $241.0 million of our 5.875% senior notes due 2022, $291.0 million of our 5.00% senior notes due 2022, $122.3 million of our 5.0% senior notes due 2023, $1.2 million of our 5.75% senior subordinated notes due 2021 and $8.3 million of our 5.00% senior subordinated notes due 2022.

Additions to natural gas and oil properties for first three months 2022 were consistent with expectations relative to our 2022 capital budget.

Repayment of senior notes for first three months 2022 includes the redemption of our $850.0 million aggregate principal amount 9.25% senior notes due 2026.

From time to time, we may continue to repurchase our senior notes based upon prevailing market or other conditions at the time.

Liquidity and Capital Resources

Our main sources of liquidity and capital resources are internally generated cash flows from operating activities, a bank credit facility with uncommitted and committed availability, access to the debt and equity capital markets and asset sales.

We must develop existing reserves to maintain or grow our production and cash flows.

We accomplish this primarily through successful drilling programs which require substantial capital expenditures.

We continue to take steps to ensure we have adequate capital resources and liquidity to fund our capital expenditure program.

In third quarter 2021, we entered into additional commodity derivative contracts for 2021 through 2023 to protect future cash flows.

During first nine months 2021, our net cash provided from operating activities of $475.3 million was used to fund approximately $332.7 million of capital expenditures (including acreage acquisitions).

At September 30, 2021, we had $478,000 in cash and total assets of $6.3 billion.

Total debt at September 30, 2021 totaled $2.9 billion, including $30.0 million outstanding on our bank credit facility and $2.9 billion of senior notes (before deducting debt issuance costs).

Our available committed borrowing capacity at September 30, 2021 was $2.0 billion under current bank commitments.

Cash is required to fund capital expenditures necessary to offset inherent declines in production and reserves that are typical in the oil and natural gas industry.

Future success in maintaining reserves and production will be highly dependent on capital resources available.

We currently believe that net cash generated from operating activities, unused committed borrowing capacity under the bank credit facility and proceeds from asset sales combined with our natural gas, NGLs and oil derivatives contracts currently in place will be adequate to satisfy near-term financial obligations and liquidity needs.

While our expectation is to operate within our internally generated cash flow, to the extent our capital requirements exceed our internally generated cash flow and proceeds from asset sales, debt or equity securities may be issued to fund these requirements.

Long-term cash flows are subject to a number of variables including the level of production and prices as well as various economic conditions that have historically affected the oil and natural gas business.

A material decline in natural gas, NGLs and oil prices or a reduction in production and reserves would reduce our ability to fund capital expenditures, meet financial obligations and operate profitably.

We establish a capital budget at the beginning of each calendar year and review it during the course of the year, taking into account various factors including the commodity price environment.

Our 2021 capital budget was announced in early February at $425.0 million.

Commodity prices have remained highly volatile but have increased during first nine months 2021 compared to fourth quarter 2020.

Our revenues, earnings, liquidity and ability to grow are substantially dependent on the prices we receive for and our ability to develop our reserves of natural gas, NGLs and oil.

We have adjusted and must continue to adjust our business through efficiencies and margin enhancements.

We plan to continue to work towards improved profitability and balance sheet strength.

We will continue to monitor the market and look for opportunities to refinance or reduce debt based on market conditions.

We believe we are well-positioned to manage any challenges during a low commodity price environment and that we can endure continued volatility in current and future commodity prices by:

exercising discipline in our capital program with the expectation of funding our capital expenditures with operating cash flow and, if required, with borrowings under our bank credit facility;

continuing to optimize our drilling, completion and operational efficiencies;

continuing to focus on improving our cost structure;

continuing to manage price risk by hedging our production volumes;

continuing to manage our balance sheet.

Credit Arrangements

As of September 30, 2021, we maintained a revolving credit facility with a borrowing base of $3.0 billion and aggregate lender commitments of $2.4 billion, which we refer to as our bank credit facility or bank debt.

The bank credit facility is secured by substantially all of our assets and has a maturity date of April 13, 2023.

Availability under the bank credit facility is subject to a borrowing base set by the lenders.

As of September 30, 2021, the outstanding balance under our bank credit facility was $30.0 million.

Additionally, we had $334.6 million of undrawn letters of credit leaving $2.0 billion of committed borrowing capacity available under the bank credit facility at the end of third quarter 2021.

Our bank credit facility imposes limitations on the payment of dividends and other restricted payments (as defined under our bank credit facility).

The bank credit facility also contains customary covenants relating to debt incurrence, liens, investments and financial ratios.

We were in compliance with all covenants at September 30, 2021.

See Note 9 to our unaudited consolidated financial statements for additional information regarding our bank debt.

Based on the current commodity price environment, we believe we have sufficient liquidity and capital resources to execute our business plan for the foreseeable future.

We continue to manage the duration and level of our drilling and completion commitments in order to maintain flexibility with regard to our activity level and capital expenditures.

As of March 31, 2022, we had cash on hand in the amount of $112.9 million.

Sources of Cash

We currently expect our 2022 capital program to be funded by cash flows from operations.

During the quarter ended March 31, 2022, we generated $406.4 million of cash flows from operating activities.

As of March 31, 2022, the remaining available borrowing capacity under our bank credit facility was $2.1 billion and we had $112.9 million cash on hand.

Our borrowing base can be adjusted as a result of changes in commodity prices, acquisitions or divestitures of proved properties or financing activities.

We may draw on our bank credit facility to meet short-term cash requirements.

In early January 2022, we issued $500.0 million aggregate principal amount of new 4.75% senior notes due 2030, with the proceeds along with cash on hand and our credit facility to fully redeem our 9.25% senior notes due 2026 in February 2022.

Although we expect cash flows and capacity under the existing credit facility to be sufficient to fund our expected 2022 capital program, we may also elect to raise funds through new debt or equity offerings or from other sources of financing.

Any downgrades in our credit ratings could make it more difficult or expensive for us to borrow additional funds.

All of our sources of liquidity can be affected by the general conditions of the broader economy, the global pandemic, force majeure events and fluctuations in commodity prices, operating costs and volumes produced, all of which affect us and our industry.

We have no control over market prices for natural gas, NGLs or oil, although we may be able to influence the amount of realized revenues through the use of derivative contracts as part of our commodity price risk management.

Bank Credit Facility

Our bank credit facility is secured by substantially all of our assets.

As of March 31, 2022, we had no outstanding borrowings under our bank credit facility and we maintained a borrowing base of $3.0 billion and aggregate lender commitments of $2.4 billion.

We also have undrawn letters of credit of $338.0 million as of March 31, 2022.

We were in compliance with applicable covenants under the bank credit facility as of March 31, 2022.

The borrowing base is subject to regular, semi-annual redeterminations and is dependent on a number of factors but primarily the lender’s assessment of future cash flows.

Our scheduled borrowing base redetermination was completed in the spring of 2022.

On April 14, 2022 we entered into an amended and restated revolving bank credit facility.

The new facility has a maximum facility amount of $4.0 billion, a borrowing base of $3.0 billion and aggregate lender commitments of $1.5 billion.

The maturity of the new bank credit facility is April 14, 2027.

See Note 8 for additional information.

Our daily weighted-average bank credit facility debt balance was $65.3 million for the three months ended March 31, 2022 compared to $220.4 million for the same period of the prior year.

As of April 14, 2022, borrowings under the amended and restated revolving bank facility can either be at the alternate base rate (“ABR,”

as defined in the bank credit facility agreement) plus a spread ranging from 0.75% to 1.75% or at the Term Benchmark Rate (as defined in the bank credit facility agreement) plus a spread ranging from 1.75% to 2.75%.

The applicable spread is dependent upon borrowings relative to the borrowing base.

We may elect, from time to time, to convert all or any part of our Term Benchmark loans to base rate loans or to convert all or any of the base rate loans to Term Benchmark loans.

We use cash for the development, exploration and acquisition of natural gas and oil properties and for the payment of gathering, transportation and processing costs, operating, general and administrative costs, taxes and debt obligations, including interest.

Expenditures for the development, exploration and acquisition of natural gas and oil properties are the primary use of our capital resources.

During first quarter 2022, we funded $102.7 million on capital expenditures as reported in our consolidated statement of cash flows.

The amount of our future capital expenditures will depend upon a number of factors including our cash flows from operating, investing and financing activities, infrastructure availability, supply and demand

fundamentals and our ability to execute our development program.

In addition, the impact of commodity prices on investment opportunities, the availability of capital and the timing and results of our development activities may lead to changes in funding requirements for future development.

We periodically review our budget to assess changes in current and projected cash flows, debt requirements and other factors.

We may from time to time repurchase or redeem all or portions of our outstanding debt securities for cash, through exchanges for other securities or a combination of both.

Such repurchases or redemptions may be made in open market transactions and will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors.

The amounts involved may be material.

As part of our strategy for 2022, we will continue to focus on improving our debt metrics.

We expect our quarterly cash dividend to be reinstated in the second half of 2022 at a quarterly dividend rate of $0.08 per share or an $0.32 per share annual distribution.

Details regarding the record and payment dates will be announced at such time the dividend is declared by our Board of Directors.

In early 2022, the board approved an increase to our share repurchase program, where we are now authorized to repurchase an additional $430.0 million of our outstanding shares of common stock for an aggregate available at the time of $500.0 million.

Shelf Registration

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The determination of the amount of future dividends, if any, to be declared and paid is at the sole discretion of the Board of Directors and primarily depends on cash flow, capital expenditures, debt covenants and various other factors.

We expect our quarterly cash dividend will be reinstated in the second half of 2022.

Cash Contractual Obligations

Our contractual obligations include long-term debt, operating leases, derivative obligations, asset retirement obligations and transportation, processing and gathering commitments including the divestiture contractual commitment.

As of September 30, 2021, we do not have any significant off-balance sheet debt or other such unrecorded obligations and we have not guaranteed any debt of any unrelated party.

As of September 30, 2021, we had a total of $334.6 million of undrawn letters of credit under our bank credit facility.

Since December 31, 2020, there have been no material changes to our contractual obligations other than the changes to our indebtedness as discussed further in Note 9 and a reduction in our divestiture contract obligation as discussed in Note 14.

As of March 31, 2022, we do not have any significant off-balance sheet debt or other such unrecorded obligations and we have not guaranteed any debt of any unrelated party.

As of March 31, 2022, we had a total of $338.0 million of undrawn letters of credit under our bank credit facility.

Since December 31, 2021, there have been no material changes to our contractual obligations other than the changes to our indebtedness as discussed further in Note 8.

Interest Rates

At September 30, 2021, we had approximately $2.9 billion of debt outstanding.

Of this amount, $2.9 billion bore interest at fixed rates averaging 6.9%.

Bank debt totaling $30.0 million bears interest at a floating rate, which was 2.4% at September 30, 2021.

The 30-day LIBOR Rate on September 30, 2021 was approximately 0.1%.

A 1% increase in short-term interest rates on the floating-rate debt outstanding on September 30, 2021 would result in approximately $300,000 in additional annual interest expense.

At March 31, 2022, we had approximately $2.6 billion of debt outstanding which bore interest at fixed rates averaging 5.7%.

Off-Balance Sheet Arrangements

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Natural gas, NGLs and oil prices are subject to significant fluctuations that are beyond our ability to control or predict.

Although certain of our costs and expenses are affected by general inflation, inflation does not normally have a significant effect on our business.

We expect costs for the remainder of 2021 to continue to be a function of supply and demand.

Certain of our costs and expenses are affected by general inflation and we expect costs for the remainder of 2022 to continue to be a function of supply and demand.

Forward-Looking Statements

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“would”

or similar words indicating that future outcomes are uncertain.

or similar words

indicating that future outcomes are uncertain.

In accordance with “safe harbor”

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These derivative instruments apply to a varying portion of our production and provide only partial price protection.

These arrangements limit the benefit to us of increases in prices but offer protection in the event of price declines.

These arrangements can limit the benefit to us of increases in prices but offer protection in the event of price declines.

Further, if our counterparties defaulted, this protection might be limited as we might not receive the benefits of the derivatives.

Realized prices are primarily driven by worldwide prices for oil and spot market prices for North American natural gas production.

Realized prices are primarily driven by worldwide prices for oil and regional index prices for North American natural gas production.

However, natural gas and NGLs prices are becoming global commodities similar to oil.

Natural gas and oil prices have been volatile and unpredictable for many years.

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We are also exposed to market risks related to changes in interest rates.

These risks did not change materially from December 31, 2020 to September 30, 2021.

These risks did not change materially from December 31, 2021 to March 31, 2022.

Commodity Price Risk

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Our program may also include a three-way collar which is a combination of three options.

At September 30, 2021, our derivative program includes swaps, calls, collars, three-way collars and swaptions.

The fair value of these contracts, represented by the estimated amount that would be realized upon immediate liquidation based on a comparison of the contract price and a reference price, generally NYMEX for natural gas and crude oil or Mont Belvieu for NGLs, as of September 30, 2021, approximated a net unrealized pretax loss of

At March 31, 2022, our derivative program includes swaps, collars, three-way collars and swaptions.

The fair value of these contracts, represented by the estimated amount that would be realized upon immediate liquidation based on a comparison of the contract price and a reference price, generally NYMEX for natural gas and crude oil or Mont Belvieu for NGLs, as of March 31, 2022, approximated a net unrealized pretax loss of

$989.8 million.

These contracts expire monthly through December 2024.

At September 30, 2021, the following commodity derivative contracts were outstanding, excluding our basis swaps which are discussed below:

At March 31, 2022, the following commodity derivative contracts were outstanding, excluding our basis swaps which are discussed below:

Contract Type

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Fair Market Value

(in thousands)

Natural Gas (1)

(in thousands)

496,655 Mmbtu/day

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149,863 Mmbtu/day

January - March 2022

200,000 Mmbtu/day

60,000 Mmbtu/day

6,833 bbls/day

5,123 bbls/day

NGLs (C3-Propane)

6,000 bbls/day

NLGs (C2-Ethane)

April-June 2022

2,681 bbls/day

NGLs (NC4-Normal Butane)

NGLs (C3-Propane)

April-June 2022

3,989 bbls/day

NGLs (NC4-Butane)

April-June 2022

3,000 bbls/day

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1,530 bbls/day

January - March 2022

2,656 bbls/day

January - March 2022

2,000 bbls/day

We also sold natural gas call swaptions of 80,000 Mmbtu/day for 2022 at a weighted average price of $2.80 and 70,000 Mmbtu/day for 2023 at a weighted average price of $3.04.

The fair market value of these swaptions at September 30, 2021 was a net derivative liability of $60.1 million.

We also sold natural gas call swaptions of 100,000 Mmbtu/day for 2023 at a weighted average price of $3.21.

The fair market value of these swaptions at March 31, 2022 was a net derivative liability of $45.9 million.

We believe NGLs prices are somewhat seasonal, particularly for propane.

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If commodity price changes in one region are not reflected in other regions, derivative commodity instruments may no longer provide the expected hedge, resulting in increased basis risk.

Therefore, in addition to the swaps, calls, collars, three-way collars and swaptions discussed above, we have entered into natural gas basis swap agreements.

Therefore, in addition to the swaps, collars, three-way collars and swaptions discussed above, we have entered into natural gas basis swap agreements.

The price we receive for our gas production can be more or less than the NYMEX Henry Hub price because of basis adjustments, relative quality and other factors.

Basis swap agreements effectively fix the basis adjustments.

The fair value of the natural gas basis swaps was a gain of $8.5 million September 30, 2021 and they settle monthly through December 2024.

At September 30, 2021, we also had propane spread swap contracts which lock in the differential between Mont Belvieu and international propane indices.

These contracts settle monthly through 2021.

The fair value of these contracts was a gain of $394,000 at September 30, 2021.

At September 30, 2021, we are entitled to receive contingent consideration associated with the sale of our North Louisiana assets, annually through 2023, of up to $75.0 million based on future achievement of certain natural gas and oil prices based on published indexes along with the realized NGLs prices of the buyer.

The fair value at September 30, 2021 was a gain of $50.2 million.

The following table shows the fair value of our derivatives and the hypothetical changes in fair value that would result from a 10% and a 25% change in commodity prices at September 30, 2021.

The fair value of the natural gas basis swaps was a gain of $22.5 million March 31, 2022 and they settle monthly through December 2024.

At March 31, 2022, we are entitled to receive contingent consideration associated with the sale of our North Louisiana assets, annually through 2023, of up to $45.5 million based on future achievement of certain natural gas and oil prices based on published indexes along with the realized NGLs prices of the buyer.

The fair value at March 31, 2022 was a gain of $34.8 million.

The following table shows the fair value of our derivatives and the hypothetical changes in fair value that would result from a 10% and a 25% change in commodity prices at March 31, 2022.

We remain at risk for possible changes in the market value of commodity derivative instruments;

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Three-way collars

Freight swaps

Divestiture contingent consideration

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Our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty.

At September 30, 2021, our derivative counterparties include nineteen financial institutions, of which all but five are secured lenders in our bank credit facility.

At March 31, 2022, our derivative counterparties include fifteen financial institutions, of which all but five are secured lenders in our bank credit facility.

Counterparty credit risk is considered when determining the fair value of our derivative contracts.

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We attempt to balance variable rate debt, fixed rate debt and debt maturities to manage interest costs, interest rate volatility and financing risk.

This is accomplished through a mix of fixed rate senior and senior subordinated debt and variable rate bank debt.

At September 30, 2021, we had $2.9 billion of debt outstanding.

Of this amount, $2.9 billion bears interest at fixed rates averaging 6.9%.

Bank debt totaling $30.0 million bears interest at floating rates, which was 2.4% on September 30, 2021.

On September 30, 2021, the 30-day LIBOR Rate was approximately 0.1%.

A 1% increase in short-term interest rates on the floating-rate debt outstanding on September 30, 2021 would result in approximately $300,000 in additional annual interest expense.

This is accomplished through a mix of fixed rate senior and variable rate bank debt.

At March 31, 2022, we had $2.6 billion of debt outstanding which bears interest at fixed rates averaging 5.7%.

CONTROLS A ND PROCEDURES

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Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC.

Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of September 30, 2021 at the reasonable assurance level.

Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of March 31, 2022 at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

There was no change in our system of internal control over financial reporting (as defined in Exchange Act Rule 13a-15(f) under the Exchange Act) during the three months ended September 30, 2021 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

There was no change in our system of internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) during the three months ended March 31, 2022 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

P ART II –

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-Q

Item 1. Financial Statements