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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark one)

☑ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2021

OR

☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number: 001-12209

RANGE RESOURCES CORPORATION

(Exact Name of Registrant as Specified in Its Charter)

Delaware |  | 34-1312571
(State or Other Jurisdiction of Incorporation or Organization) |  | (IRS Employer Identification No.)
100 Throckmorton Street, Suite 1200 Fort Worth, Texas |  | 76102
(Address of Principal Executive Offices) |  | (Zip Code)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class |  | Trading Symbol(s) |  | Name of each exchange on which registered
Common Stock, (Par Value $0.01) |  | RRC |  | New York Stock Exchange

Registrant’s telephone number, including area code

(817) 870-2601

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes  No 

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).

Yes  No 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large Accelerated Filer |  |  | Accelerated Filer |  | 
Non-Accelerated Filer |  |  | Smaller Reporting Company |  | ☐
|  |  | Emerging Growth Company |  | ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. |  | 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes ☐ No 

259,794,788 Common Shares were outstanding on October 22, 2021

RANGE RESOURCES CORPORATION

FORM 10-Q

Quarter Ended September 30, 2021

Unless the context otherwise indicates, all references in this report to “Range Resources,” “Range,” “we,” “us,” or “our” are to Range Resources Corporation and its directly and indirectly owned subsidiaries. For certain industry specific terms used in this Form 10-Q, please see “Glossary of Certain Defined Terms” in our 2020 Annual Report on Form 10-K.

TABLE OF CONTENTS

|  |  |  | Page
PART I – FINANCIAL INFORMATION |  |
ITEM 1. |  | Financial Statements: |  |
|  | Consolidated Balance Sheets |  | 3
|  | Consolidated Statements of Operations (Unaudited) |  | 4
|  | Consolidated Statements of Comprehensive Loss (Unaudited) |  | 5
|  | Consolidated Statements of Cash Flows (Unaudited) |  | 6
|  | Consolidated Statements of Stockholders’ Equity (Unaudited) |  | 7
|  | Notes to Consolidated Financial Statements (Unaudited) |  | 9
ITEM 2. |  | Management’s Discussion and Analysis of Financial Condition and Results of Operations |  | 27
ITEM 3. |  | Quantitative and Qualitative Disclosures about Market Risk |  |
ITEM 4. |  | Controls and Procedures |  | 44
PART II – OTHER INFORMATION |  |
ITEM 1. |  | Legal Proceedings |  | 44
ITEM 1A. |  | Risk Factors |  | 44
ITEM 2. |  | Unregistered Sales of Equity Securities and Use of Proceeds |  | 44
ITEM 6. |  | Exhibits |  | 45
|  | SIGNATURES |  | 46

2

P ART I – FINANCIAL INFORMATION

ITEM 1. Financial Statements

RANGE RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS

(In thousands, except per share data)

|  | September 30, |  |  | December 31, |
|  | 2021 |  |  | 2020 |
Assets |  | (Unaudited) |  |  |  |
Current assets: |  |  |  |  |  |
Cash and cash equivalents |  | $ | 478 |  |  | $ | 458 |
Accounts receivable, less allowance for doubtful accounts of $373 and $3,004 |  |  | 366,695 |  |  |  | 252,642 |
Derivative assets |  |  | 28,145 |  |  |  | 23,332 |
Other current assets |  |  | 17,037 |  |  |  | 13,408 |
Total current assets |  |  | 412,355 |  |  |  | 289,840 |
Derivative assets |  |  | 25,518 |  |  |  | 16,680 |
Natural gas properties, successful efforts method |  |  | 10,068,245 |  |  |  | 9,751,114 |
Accumulated depletion and depreciation |  |  | (4,330,289 | ) |  |  | (4,064,305 | )
|  |  | 5,737,956 |  |  |  | 5,686,809 |
Other property and equipment |  |  | 74,167 |  |  |  | 79,878 |
Accumulated depreciation and amortization |  |  | (70,734 | ) |  |  | (75,717 | )
|  |  | 3,433 |  |  |  | 4,161 |
Operating lease right-of-use assets |  |  | 46,543 |  |  |  | 63,581 |
Other assets |  |  | 78,384 |  |  |  | 75,865 |
Total assets |  | $ | 6,304,189 |  |  | $ | 6,136,936 |
Liabilities |  |  |  |  |  |
Current liabilities: |  |  |  |  |  |
Accounts payable |  | $ | 151,919 |  |  | $ | 132,421 |
Asset retirement obligations |  |  | 6,689 |  |  |  | 6,689 |
Accrued liabilities |  |  | 448,950 |  |  |  | 348,333 |
Accrued interest |  |  | 43,514 |  |  |  | 54,742 |
Derivative liabilities |  |  | 685,285 |  |  |  | 26,707 |
Divestiture contract obligation |  |  | 92,061 |  |  |  | 92,593 |
Current maturities of long-term debt |  |  | 217,909 |  |  |  | 45,356 |
Total current liabilities |  |  | 1,646,327 |  |  |  | 706,841 |
Bank debt |  |  | 23,976 |  |  |  | 693,123 |
Senior notes |  |  | 2,706,495 |  |  |  | 2,329,745 |
Senior subordinated notes |  |  | — |  |  |  | 17,384 |
Deferred tax liabilities |  |  | 99,855 |  |  |  | 135,267 |
Derivative liabilities |  |  | 85,436 |  |  |  | 9,746 |
Deferred compensation liabilities |  |  | 112,235 |  |  |  | 81,481 |
Operating lease liabilities |  |  | 27,839 |  |  |  | 43,155 |
Asset retirement obligations and other liabilities |  |  | 86,247 |  |  |  | 91,157 |
Divestiture contract obligation |  |  | 334,495 |  |  |  | 391,502 |
Total liabilities |  |  | 5,122,905 |  |  |  | 4,499,401 |
Commitments and contingencies |  |  |  |  |  |
Stockholders’ Equity |  |  |  |  |  |
Preferred stock, $1 par, 10,000,000 shares authorized, no ne issued and outstanding |  |  | — |  |  |  | — |
Common stock, $0.01 par, 475,000,000 shares authorized, 259,787,004 issued at September 30, 2021 and 256,353,887 issued at December 31, 2020 |  |  | 2,598 |  |  |  | 2,563 |
Common stock held in treasury, 10,002,646 shares at September 30, 2021 and 10,005,795 shares at December 31, 2020 |  |  | (30,007 | ) |  |  | (30,132 | )
Additional paid-in capital |  |  | 5,707,382 |  |  |  | 5,684,268 |
Accumulated other comprehensive loss |  |  | (268 | ) |  |  | (479 | )
Retained deficit |  |  | (4,498,421 | ) |  |  | (4,018,685 | )
Total stockholders’ equity |  |  | 1,181,284 |  |  |  | 1,637,535 |
Total liabilities and stockholders’ equity |  | $ | 6,304,189 |  |  | $ | 6,136,936 |

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

3

RANGE RESOURCES CORPORATION

CO NSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited, in thousands, except per share data)

|  | Three Months Ended September 30, |  |  | Nine Months Ended September 30, |
|  | 2021 |  |  | 2020 |  |  | 2021 |  |  | 2020 |
Revenues and other income: |  |  |  |  |  |  |  |  |  |  |  |
Natural gas, NGLs and oil sales |  | $ | 849,305 |  |  | $ | 381,553 |  |  | $ | 2,074,507 |  |  | $ | 1,162,907 |
Derivative fair value (loss) income |  |  | (652,220 | ) |  |  | (124,690 | ) |  |  | (959,782 | ) |  |  | 102,182 |
Brokered natural gas, marketing and other |  |  | 105,554 |  |  |  | 42,482 |  |  |  | 248,668 |  |  |  | 104,722 |
Total revenues and other income |  |  | 302,639 |  |  |  | 299,345 |  |  |  | 1,363,393 |  |  |  | 1,369,811 |
Costs and expenses: |  |  |  |  |  |  |  |  |  |  |  |
Direct operating |  |  | 20,245 |  |  |  | 19,515 |  |  |  | 57,653 |  |  |  | 75,944 |
Transportation, gathering, processing and compression |  |  | 296,510 |  |  |  | 268,108 |  |  |  | 853,684 |  |  |  | 831,748 |
Production and ad valorem taxes |  |  | 7,140 |  |  |  | 6,106 |  |  |  | 20,179 |  |  |  | 20,682 |
Brokered natural gas and marketing |  |  | 105,838 |  |  |  | 47,967 |  |  |  | 247,177 |  |  |  | 118,752 |
Exploration |  |  | 5,881 |  |  |  | 8,086 |  |  |  | 16,447 |  |  |  | 23,190 |
Abandonment and impairment of unproved properties |  |  | 2,000 |  |  |  | 5,667 |  |  |  | 7,206 |  |  |  | 16,604 |
General and administrative |  |  | 49,061 |  |  |  | 38,153 |  |  |  | 127,307 |  |  |  | 118,695 |
Exit and termination costs |  |  | 11,789 |  |  |  | 521,633 |  |  |  | 9,557 |  |  |  | 533,525 |
Deferred compensation plan |  |  | 34,278 |  |  |  | 6,237 |  |  |  | 89,551 |  |  |  | 10,287 |
Interest |  |  | 56,809 |  |  |  | 47,999 |  |  |  | 170,974 |  |  |  | 144,141 |
Loss (gain) on early extinguishment of debt |  | — |  |  |  | 7,821 |  |  |  | 98 |  |  |  | (14,093 | )
Depletion, depreciation and amortization |  |  | 93,116 |  |  |  | 96,167 |  |  |  | 272,128 |  |  |  | 303,779 |
Impairment of proved properties and other assets |  |  | — |  |  |  | 1,955 |  |  |  | — |  |  |  | 78,955 |
(Gain) loss on the sale of assets |  |  | (78 | ) |  |  | 9,230 |  |  |  | (724 | ) |  |  | (112,443 | )
Total costs and expenses |  |  | 682,589 |  |  |  | 1,084,644 |  |  |  | 1,871,237 |  |  |  | 2,149,766 |
Loss before income taxes |  |  | (379,950 | ) |  |  | (785,299 | ) |  |  | (507,844 | ) |  |  | (779,955 | )
Income tax expense (benefit): |  |  |  |  |  |  |  |  |  |  |  |
Current |  |  | 4,484 |  |  |  | — |  |  |  | 7,221 |  |  |  | (366 | )
Deferred |  |  | (34,167 | ) |  |  | (36,509 | ) |  |  | (35,477 | ) |  |  | (29,411 | )
|  |  | (29,683 | ) |  |  | (36,509 | ) |  |  | (28,256 | ) |  |  | (29,777 | )
Net loss |  | $ | (350,267 | ) |  | $ | (748,790 | ) |  | $ | (479,588 | ) |  | $ | (750,178 | )
Net loss per common share: |  |  |  |  |  |  |  |  |  |  |  |
Basic |  | $ | (1.44 | ) |  | $ | (3.12 | ) |  | $ | (1.98 | ) |  | $ | (3.10 | )
Diluted |  | $ | (1.44 | ) |  | $ | (3.12 | ) |  | $ | (1.98 | ) |  | $ | (3.10 | )
Weighted average common shares outstanding: |  |  |  |  |  |  |  |  |  |  |  |
Basic |  |  | 243,311 |  |  |  | 239,895 |  |  |  | 242,692 |  |  |  | 241,770 |
Diluted |  |  | 243,311 |  |  |  | 239,895 |  |  |  | 242,692 |  |  |  | 241,770 |

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

4

RANGE RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF COMP REHENSIVE LOSS

(Unaudited, in thousands)

|  | Three Months Ended September 30, |  |  | Nine Months Ended September 30, |
|  | 2021 |  |  | 2020 |  |  | 2021 |  |  | 2020 |
Net loss |  | $ | (350,267 | ) |  | $ | (748,790 | ) |  | $ | (479,588 | ) |  | $ | (750,178 | )
Other comprehensive loss: |  |  |  |  |  |  |  |  |  |  |  |
Postretirement benefits: |  |  |  |  |  |  |  |  |  |  |  |
Actuarial gain |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 7 |
Amortization of prior service costs |  |  | 92 |  |  |  | 92 |  |  |  | 277 |  |  |  | 277 |
Income tax expense |  |  | (22 | ) |  |  | (22 | ) |  |  | (66 | ) |  |  | (70 | )
Total comprehensive loss |  | $ | (350,197 | ) |  | $ | (748,720 | ) |  | $ | (479,377 | ) |  | $ | (749,964 | )

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

5

RANGE RESOURCES CORPORATION

CO NSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited, in thousands)

|  | Nine Months Ended September 30, |
|  | 2021 |  |  | 2020 |
Operating activities: |  |  |  |  |  |
Net loss |  | $ | (479,588 | ) |  | $ | (750,178 | )
Adjustments to reconcile net loss to net cash provided from operating activities: |  |  |  |  |  |
Deferred income tax benefit |  |  | (35,477 | ) |  |  | (29,411 | )
Depletion, depreciation and amortization and impairment of proved properties |  |  | 272,128 |  |  |  | 382,734 |
Abandonment and impairment of unproved properties |  |  | 7,206 |  |  |  | 16,604 |
Derivative fair value loss (income) |  |  | 959,782 |  |  |  | (102,182 | )
Cash settlements on derivative financial instruments |  |  | (239,165 | ) |  |  | 305,243 |
Divestiture contract obligation, including accretion, net of gain |  |  | 8,467 |  |  |  | 486,689 |
Allowance for bad debt |  |  | — |  |  |  | 400 |
Amortization of deferred financing costs and other |  |  | 6,253 |  |  |  | 5,023 |
Deferred and stock-based compensation |  |  | 119,946 |  |  |  | 38,380 |
Gain on the sale of assets |  |  | (724 | ) |  |  | (112,443 | )
Loss (gain) on early extinguishment of debt |  |  | 98 |  |  |  | (14,093 | )
Changes in working capital: |  |  |  |  |  |
Accounts receivable |  |  | (116,204 | ) |  |  | 91,343 |
Other current assets |  |  | (3,574 | ) |  |  | (5,786 | )
Accounts payable |  |  | 34,313 |  |  |  | (52,820 | )
Accrued liabilities and other |  |  | (58,172 | ) |  |  | (80,529 | )
Net cash provided from operating activities |  |  | 475,289 |  |  |  | 178,974 |
Investing activities: |  |  |  |  |  |
Additions to natural gas properties |  |  | (311,709 | ) |  |  | (321,849 | )
Additions to field service assets |  |  | (720 | ) |  |  | (2,493 | )
Acreage purchases |  |  | (20,302 | ) |  |  | (18,554 | )
Proceeds from disposal of assets |  |  | 237 |  |  |  | 246,083 |
Purchases of marketable securities held by the deferred compensation plan |  |  | (24,396 | ) |  |  | (14,855 | )
Proceeds from the sales of marketable securities held by the deferred compensation plan |  |  | 27,974 |  |  |  | 20,974 |
Net cash used in investing activities |  |  | (328,916 | ) |  |  | (90,694 | )
Financing activities: |  |  |  |  |  |
Borrowings on credit facilities |  |  | 1,250,000 |  |  |  | 1,676,000 |
Repayments on credit facilities |  |  | (1,922,000 | ) |  |  | (1,447,000 | )
Issuance of senior notes |  |  | 600,000 |  |  |  | 850,000 |
Repayment of senior or senior subordinated notes |  |  | (63,324 | ) |  |  | (1,120,634 | )
Treasury stock purchases |  |  | — |  |  |  | (22,992 | )
Debt issuance costs |  |  | (8,799 | ) |  |  | (12,735 | )
Taxes paid for shares withheld |  |  | (9,267 | ) |  |  | (2,841 | )
Change in cash overdrafts |  |  | 1,515 |  |  |  | (8,797 | )
Proceeds from the sales of common stock held by the deferred compensation plan |  |  | 5,522 |  |  |  | 690 |
Net cash used in financing activities |  |  | (146,353 | ) |  |  | (88,309 | )
Increase (decrease) in cash and cash equivalents |  |  | 20 |  |  |  | (29 | )
Cash and cash equivalents at beginning of period |  |  | 458 |  |  |  | 546 |
Cash and cash equivalents at end of period |  | $ | 478 |  |  | $ | 517 |

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

6

RANGE RESOURCES CORPORATION

CONSOLIDATED STATEMENTS O F STOCKHOLDERS’ EQUITY

(Unaudited, in thousands)

Fiscal Year 2021 |  |  |  |  |  |  |  | Common |  |  |  |  |  |  |  |  | Accumulated |  |  |  |
|  |  |  |  |  |  |  | stock |  |  | Additional |  |  |  |  |  | other |  |  |  |
|  | Common stock |  |  | held in |  |  | paid-in |  |  | Retained |  |  | comprehensive |  |  |  |
|  | Shares |  |  | Par value |  |  | treasury |  |  | capital |  |  | deficit |  |  | loss |  |  | Total |
Balance as of December 31, 2020 |  |  | 256,354 |  |  | $ | 2,563 |  |  | $ | (30,132 | ) |  | $ | 5,684,268 |  |  | $ | (4,018,685 | ) |  | $ | (479 | ) |  | $ | 1,637,535 |
Issuance of common stock |  |  | 3,218 |  |  |  | 33 |  |  |  | — |  |  |  | (7,654 | ) |  |  | — |  |  |  | — |  |  |  | (7,621 | )
Issuance of common stock upon vesting of PSUs |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 148 |  |  |  | (148 | ) |  |  | — |  |  |  | — |
Stock-based compensation expense |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 6,713 |  |  |  | — |  |  |  | — |  |  |  | 6,713 |
Treasury stock |  |  | — |  |  |  | — |  |  |  | 47 |  |  |  | (47 | ) |  |  | — |  |  |  | — |  |  |  | — |
Other comprehensive income |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 70 |  |  |  | 70 |
Net income |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 27,151 |  |  |  | — |  |  |  | 27,151 |
Balance as of March 31, 2021 |  |  | 259,572 |  |  |  | 2,596 |  |  |  | (30,085 | ) |  |  | 5,683,428 |  |  |  | (3,991,682 | ) |  |  | (409 | ) |  |  | 1,663,848 |
Issuance of common stock |  |  | 206 |  |  |  | 2 |  |  |  | — |  |  |  | 9,289 |  |  |  | — |  |  |  | — |  |  |  | 9,291 |
Stock-based compensation expense |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 6,523 |  |  |  | — |  |  |  | — |  |  |  | 6,523 |
Treasury stock |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Other comprehensive income |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 71 |  |  |  | 71 |
Net loss |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (156,472 | ) |  |  | — |  |  |  | (156,472 | )
Balance as of June 30, 2021 |  |  | 259,778 |  |  |  | 2,598 |  |  |  | (30,085 | ) |  |  | 5,699,240 |  |  |  | (4,148,154 | ) |  |  | (338 | ) |  |  | 1,523,261 |
Issuance of common stock |  |  | 9 |  |  |  | — |  |  |  | — |  |  |  | 754 |  |  |  | — |  |  |  | — |  |  |  | 754 |
Stock-based compensation expense |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 7,466 |  |  |  | — |  |  |  | — |  |  |  | 7,466 |
Treasury stock |  |  | — |  |  |  | — |  |  |  | 78 |  |  |  | (78 | ) |  |  | — |  |  |  | — |  |  |  | — |
Other comprehensive income |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 70 |  |  |  | 70 |
Net loss |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (350,267 | ) |  |  | — |  |  |  | (350,267 | )
Balance as of September 30, 2021 |  |  | 259,787 |  |  | $ | 2,598 |  |  | $ | (30,007 | ) |  | $ | 5,707,382 |  |  | $ | (4,498,421 | ) |  | $ | (268 | ) |  | $ | 1,181,284 |

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

7

RANGE RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(Unaudited, in thousands, except per share data)

Fiscal Year 2020 |  |  |  |  |  |  |  | Common |  |  |  |  |  |  |  |  | Accumulated |  |  |  |
|  |  |  |  |  |  |  | stock |  |  | Additional |  |  |  |  |  | other |  |  |  |
|  | Common stock |  |  | held in |  |  | paid-in |  |  | Retained |  |  | comprehensive |  |  |  |
|  | Shares |  |  | Par value |  |  | treasury |  |  | capital |  |  | deficit |  |  | loss |  |  | Total |
Balance as of December 31, 2019 |  |  | 251,439 |  |  | $ | 2,514 |  |  | $ | (7,236 | ) |  | $ | 5,659,832 |  |  | $ | (3,306,834 | ) |  | $ | (788 | ) |  | $ | 2,347,488 |
Issuance of common stock |  |  | 4,246 |  |  |  | 42 |  |  |  | — |  |  |  | (1,406 | ) |  |  | — |  |  |  | — |  |  |  | (1,364 | )
Stock-based compensation expense |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 5,963 |  |  |  | — |  |  |  | — |  |  |  | 5,963 |
Treasury stock |  |  | — |  |  |  | — |  |  |  | (22,514 | ) |  |  | (33 | ) |  |  | — |  |  |  | — |  |  |  | (22,547 | )
Other comprehensive income |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 73 |  |  |  | 73 |
Net income |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 166,195 |  |  |  | — |  |  |  | 166,195 |
Balance as of March 31, 2020 |  |  | 255,685 |  |  |  | 2,556 |  |  |  | (29,750 | ) |  |  | 5,664,356 |  |  |  | (3,140,639 | ) |  |  | (715 | ) |  |  | 2,495,808 |
Issuance of common stock |  |  | 376 |  |  |  | 4 |  |  |  | — |  |  |  | 854 |  |  |  | — |  |  |  | — |  |  |  | 858 |
Issuance of common stock upon vesting of PSUs |  |  | 19 |  |  |  | — |  |  |  | — |  |  |  | 74 |  |  |  | (74 | ) |  |  | — |  |  |  | — |
Stock-based compensation expense |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 7,312 |  |  |  | — |  |  |  | — |  |  |  | 7,312 |
Treasury stock |  |  | — |  |  |  | — |  |  |  | (444 | ) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (444 | )
Other comprehensive income |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 71 |  |  |  | 71 |
Net loss |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (167,583 | ) |  |  | — |  |  |  | (167,583 | )
Balance as of June 30, 2020 |  |  | 256,080 |  |  |  | 2,560 |  |  |  | (30,194 | ) |  |  | 5,672,596 |  |  |  | (3,308,296 | ) |  |  | (644 | ) |  |  | 2,336,022 |
Issuance of common stock |  |  | 152 |  |  |  | 2 |  |  |  | — |  |  |  | 73 |  |  |  | — |  |  |  | — |  |  |  | 75 |
Stock-based compensation expense |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 6,591 |  |  |  | — |  |  |  | — |  |  |  | 6,591 |
Treasury stock |  |  | — |  |  |  | — |  |  |  | 63 |  |  |  | (63 | ) |  |  | — |  |  |  | — |  |  |  | — |
Other comprehensive income |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 70 |  |  |  | 70 |
Net loss |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (748,790 | ) |  |  | — |  |  |  | (748,790 | )
Balance as of September 30, 2020 |  |  | 256,232 |  |  |  | 2,562 |  |  |  | (30,131 | ) |  |  | 5,679,197 |  |  |  | (4,057,086 | ) |  |  | (574 | ) |  |  | 1,593,968 |

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

8

RANGE RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANC IAL STATEMENTS (UNAUDITED)

(1) SUMMARY OF ORGANIZATION AND NATURE OF BUSINESS

Range Resources Corporation is a Fort Worth, Texas-based independent natural gas, natural gas liquids (NGLs) and oil company engaged in the exploration, development and acquisition of natural gas properties in the Appalachian region of the United States. Our objective is to build stockholder value through returns-focused development of natural gas properties. Range is a Delaware corporation with our common stock listed and traded on the New York Stock Exchange under the symbol “RRC.”

(2) BASIS OF PRESENTATION

These consolidated financial statements are unaudited but, in the opinion of management, reflect all adjustments necessary for a fair statement of the results for the periods reported. All adjustments are of a normal recurring nature unless otherwise disclosed. These consolidated financial statements, including selected notes, have been prepared in accordance with the applicable rules of the Securities Exchange Commission (the SEC) and do not include all of the information and disclosures required by accounting principles generally accepted in the United States of America (U.S. GAAP) for complete financial statements.

These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in our 2020 Annual Report on Form 10-K filed with the SEC on February 23, 2021. 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.

(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.

9

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.

(5) REVENUES FROM CONTRACTS WITH CUSTOMERS

Disaggregation of Revenue

We have three material revenue streams in our business: natural gas sales, NGLs sales and condensate sales (referred to below as oil sales). 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. Revenue attributable to each of our identified revenue streams is disaggregated below (in thousands):

|  | Three Months Ended September 30, |  |  | Nine Months Ended September 30, |
|  | 2021 |  |  | 2020 |  |  | 2021 |  |  | 2020 |
Natural gas sales |  | $ | 494,917 |  |  | $ | 211,638 |  |  | $ | 1,152,283 |  |  | $ | 679,094 |
NGLs sales |  |  | 309,232 |  |  |  | 149,263 |  |  |  | 795,173 |  |  |  | 416,885 |
Oil sales |  |  | 45,156 |  |  |  | 20,652 |  |  |  | 127,051 |  |  |  | 66,928 |
Total natural gas, NGLs and oil sales |  |  | 849,305 |  |  |  | 381,553 |  |  |  | 2,074,507 |  |  |  | 1,162,907 |
Sales of purchased natural gas |  |  | 101,095 |  |  |  | 39,180 |  |  |  | 231,335 |  |  |  | 94,364 |
Sales of purchased NGLs |  |  | 2,764 |  |  |  | 1,084 |  |  |  | 3,912 |  |  |  | 3,230 |
Other marketing revenue (1) |  |  | 1,695 |  |  |  | 2,218 |  |  |  | 13,421 |  |  |  | 7,128 |
Total |  | $ | 954,859 |  |  | $ | 424,035 |  |  | $ | 2,323,175 |  |  | $ | 1,267,629 |

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

(6) INCOME TAXES

We evaluate and update our annual effective income tax rate on a quarterly basis based on current and forecasted operating results and tax laws. Consequently, based upon the mix and timing of our actual earnings compared to annual projections, our effective tax rate may vary quarterly and may make comparisons not meaningful. The effective income tax rate is influenced by a variety of factors including geographic sources and relative magnitude of these sources of income. 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. Current income taxes reflect estimated state income taxes due for 2021 which is based on our estimated earnings, taking into account state tax rates and laws regarding NOL limitations.

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(7) INCOME (LOSS) PER COMMON SHARE

Basic income or loss per share attributable to common shareholders is computed as (1) income or loss attributable to common shareholders (2) less income allocable to participating securities (3) divided by weighted average basic shares outstanding. Diluted income or loss per share attributable to common shareholders is computed as (1) basic income or loss attributable to common shareholders (2) plus diluted adjustments to income allocable to participating securities (3) divided by weighted average diluted shares outstanding. The following sets forth a reconciliation of income or loss attributable to common shareholders to basic income or loss attributable to common shareholders to diluted income or loss attributable to common shareholders (in thousands, except per share amounts):

|  | Three Months Ended September 30, |  |  | Nine Months Ended September 30, |
|  | 2021 |  |  | 2020 |  |  | 2021 |  |  | 2020 |
Net loss, as reported |  | $ | (350,267 | ) |  | $ | (748,790 | ) |  | $ | (479,588 | ) |  | $ | (750,178 | )
Participating earnings (a) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Basic net loss attributed to common shareholders |  |  | (350,267 | ) |  |  | (748,790 | ) |  |  | (479,588 | ) |  |  | (750,178 | )
Reallocation of participating earnings (a) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Diluted net loss attributed to common shareholders |  | $ | (350,267 | ) |  | $ | (748,790 | ) |  | $ | (479,588 | ) |  | $ | (750,178 | )
Net loss per common share: |  |  |  |  |  |  |  |  |  |  |  |
Basic |  | $ | (1.44 | ) |  | $ | (3.12 | ) |  | $ | (1.98 | ) |  | $ | (3.10 | )
Diluted |  | $ | (1.44 | ) |  | $ | (3.12 | ) |  | $ | (1.98 | ) |  | $ | (3.10 | )

(a) | Restricted Stock Awards represent participating securities because they participate in nonforfeitable dividends or distributions with common equity owners. Income allocable to participating securities represents the distributed and undistributed earnings attributable to the participating securities. Participating securities, however, do not participate in undistributed net losses.

The following details weighted average common shares outstanding and diluted weighted average common shares outstanding (in thousands):

|  | Three Months Ended September 30, |  |  | Nine Months Ended September 30, |
|  | 2021 |  |  | 2020 |  |  | 2021 |  |  | 2020 |
Weighted average common shares outstanding – basic and diluted |  |  | 243,311 |  |  |  | 239,895 |  |  |  | 242,692 |  |  |  | 241,770 |

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.

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

|  | September 30, 2021 |  |  | December 31, 2020 |
|  | (in thousands) |
Natural gas properties: |  |  |  |  |  |
Properties subject to depletion |  | $ | 9,203,586 |  |  | $ | 8,891,348 |
Unproved properties |  |  | 864,659 |  |  |  | 859,766 |
Total |  |  | 10,068,245 |  |  |  | 9,751,114 |
Accumulated depletion and depreciation |  |  | (4,330,289 | ) |  |  | (4,064,305 | )
Net capitalized costs |  | $ | 5,737,956 |  |  | $ | 5,686,809 |

(a) | Includes capitalized asset retirement costs and the associated accumulated amortization.

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(9) 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, 2021 |  |  | December 31, 2020 |
Bank debt (2.4%) |  | $ | 30,000 |  |  | $ | 702,000 |
Senior notes: |  |  |  |  |  |
4.875% senior notes due 2025 |  |  | 750,000 |  |  |  | 750,000 |
5.00% senior notes due 2022 |  |  | 169,589 |  |  |  | 169,589 |
5.00% senior notes due 2023 |  |  | 532,335 |  |  |  | 532,335 |
5.75% senior notes due 2021 |  |  | — |  |  |  | 25,496 |
5.875% senior notes due 2022 |  |  | 48,528 |  |  |  | 48,528 |
8.25% senior notes due 2029 |  |  | 600,000 |  |  |  | — |
9.25% senior notes due 2026 |  |  | 850,000 |  |  |  | 850,000 |
Other senior notes due 2022 |  |  | — |  |  |  | 490 |
Total senior notes |  |  | 2,950,452 |  |  |  | 2,376,438 |
Senior subordinated notes: |  |  |  |  |  |
5.00% senior subordinated notes due 2022 |  |  | — |  |  |  | 9,730 |
5.00% senior subordinated notes due 2023 |  |  | — |  |  |  | 7,712 |
5.75% senior subordinated notes due 2021 |  |  | — |  |  |  | 19,896 |
Total senior subordinated notes |  |  | — |  |  |  | 37,338 |
Total debt |  |  | 2,980,452 |  |  |  | 3,115,776 |
Unamortized premium |  |  | 254 |  |  |  | 457 |
Unamortized debt issuance costs |  |  | (32,326 | ) |  |  | (30,625 | )
Total debt net of debt issuance costs |  |  | 2,948,380 |  |  |  | 3,085,608 |
Less current maturities of long-term debt |  |  | (217,909 | ) |  |  | (45,356 | )
Total long-term debt |  | $ | 2,730,471 |  |  | $ | 3,040,252 |

Bank Debt

In April 2018, we entered into an amended and restated revolving bank facility, which we refer to as our bank debt or our bank credit facility, which is secured by substantially all of our assets and has a maturity date of April 13, 2023. The bank credit facility provides for a maximum facility amount of $4.0 billion and an initial borrowing base of $3.0 billion. 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. 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%. 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. 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. Additionally, we had $334.6 million of undrawn letters of credit, leaving $2.0 billion of committed borrowing capacity available under the facility.

New Senior Notes

In January 2021, we issued $600.0 million aggregate principal amount of 8.25% senior notes due 2029 (the 8.25% Notes) for net proceeds of $590.8 million after underwriting expenses and commissions of $9.2 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%

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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. 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 8.25% Notes. Upon occurrence of certain changes in control, we must offer to repurchase the 8.25% Notes. The 8.25% 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.

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):

|  | Outstanding Principal Amount |
5.75% senior notes due 2021 |  | $ | 25,496 |
5.875% senior notes due 2022 |  | $ | 490 |
5.75% senior subordinated notes 2021 |  | $ | 19,896 |
5.00% senior subordinated notes 2022 |  | $ | 9,730 |
5.00% senior subordinated notes 2023 |  | $ | 7,712 |

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.

Senior Notes

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.

Guarantees

Range is a holding company which owns no operating assets and has no significant operations independent of its subsidiaries. The guarantees by our subsidiaries, which are directly or indirectly owned by Range, of our senior notes and our bank credit facility are full and unconditional and joint and several, subject to certain customary release provisions. The assets, liabilities and results of operations of Range and our guarantor subsidiaries are not materially different than our consolidated financial statements. A subsidiary guarantor may be released from its obligations under the guarantee:


in the event of a sale or other disposition of all or substantially all of the assets of the subsidiary guarantor or a sale or other disposition of all the capital stock of the subsidiary guarantor, to any corporation or other person (including an unrestricted subsidiary of Range) by way of merger, consolidation, or otherwise; or

if Range designates any restricted subsidiary that is a guarantor to be an unrestricted subsidiary in accordance with the terms of the indenture.

Debt Covenants

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. 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.

(10) ASSET RETIREMENT OBLIGATIONS

Our asset retirement obligations primarily represent the estimated present value of the amounts we will incur to plug, abandon and remediate our producing properties at the end of their productive lives. Significant inputs used in determining such obligations include estimates of plugging and abandonment costs, estimated future inflation rates and well lives. The inputs are calculated based on historical data as well as current estimated costs. A reconciliation of our liability for plugging

13

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

|  | Nine Months Ended September 30, 2021 |  |  | Year Ended December 31, 2020 |
Beginning of period |  | $ | 79,822 |  |  | $ | 251,076 |
Liabilities incurred |  |  | 88 |  |  |  | 1,483 |
Acquisitions |  |  | — |  |  |  | 123 |
Liabilities settled |  |  | (5,719 | ) |  |  | (4,634 | )
Disposition of wells |  |  | — |  |  |  | (176,748 | )
Accretion expense |  |  | 4,257 |  |  |  | 7,518 |
Change in estimate |  |  | 2,856 |  |  |  | 1,004 |
End of period |  |  | 81,304 |  |  |  | 79,822 |
Less current portion |  |  | (6,689 | ) |  |  | (6,689 | )
Long-term asset retirement obligations |  | $ | 74,615 |  |  | $ | 73,133 |

Accretion expense is recognized as a component of depreciation, depletion and amortization expense in the accompanying consolidated statements of operations.

(11) DERIVATIVE ACTIVITIES

We use commodity-based derivative contracts to manage exposure to commodity price fluctuations. 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. These contracts expire monthly through December 2023. 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:

Period |  | Contract Type |  | Volume Hedged |  | Weighted Average Hedge Price
|  |  |  |  |  | Swap |  | Sold Put |  | Floor |  | Ceiling
Natural Gas (1) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
2021 |  | Swaps |  | 583,152 Mmbtu/day |  | $ | 2.84 |  |  |  |  |  |  |  |
2021 |  | Collars |  | 227,391 Mmbtu/day |  |  |  |  |  |  | $ | 2.87 |  | $ | 3.42
2021 |  | Three-way Collars |  | 339,457 Mmbtu/day |  |  |  | $ | 2.26 |  | $ | 2.62 |  | $ | 3.04
2022 |  | Swaps |  | 382,329 Mmbtu/day |  | $ | 3.11 |  |  |  |  |  |  |  |
2022 |  | Collars |  | 213,438 Mmbtu/day |  |  |  |  |  |  | $ | 3.26 |  | $ | 3.70
2022 |  | Three-way Collars |  | 251,781 Mmbtu/day |  |  |  | $ | 2.37 |  | $ | 3.03 |  | $ | 3.77
January - March 2022 |  | Calls |  | 80,000 Mmbtu/day |  |  |  |  |  |  |  |  |  | $ | 6.02
2023 |  | Swaps |  | 60,000 Mmbtu/day |  | $ | 3.27 |  |  |  |  |  |  |  |
Crude Oil |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
2021 |  | Swaps |  | 7,500 bbls/day |  | $ | 56.92 |  |  |  |  |  |  |  |
2022 |  | Swaps |  | 5,811 bbls/day |  | $ | 59.59 |  |  |  |  |  |  |  |
2023 |  | Swaps |  | 500 bbls/day |  | $ | 63.50 |  |  |  |  |  |  |  |
NGLs (C3-Propane) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
2021 |  | Swaps |  | 6,000 bbls/day |  | $ | 1.17/gallon |  |  |  |  |  |  |  |
2021 |  | Collars |  | 4,000 bbls/day |  |  |  |  |  |  | $ | 1.00/gallon |  | $ | $1.20/gallon
NGLs (NC4-Normal Butane) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
2021 |  | Swaps |  | 2,663 bbls/day |  | $ | 1.17/gallon |  |  |  |  |  |  |  |
2021 |  | Collars |  | 2,000 bbls/day |  |  |  |  |  |  | $ | 1.00/gallon |  | $ | 1.20/gallon
NGLs (C5-Natural Gasoline) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
2021 |  | Swaps |  | 2,000 bbls/day |  | $ | 1.41/gallon |  |  |  |  |  |  |  |
2021 |  | Collars |  | 3,000 bbls/day |  |  |  |  |  |  | $ | 1.35/gallon |  | $ | 1.55/gallon
January - March 2022 |  | Swaps |  | 2,656 bbls/day |  | $ | 1.59/gallon |  |  |  |  |  |  |  |
January - March 2022 |  | Collars |  | 2,000 bbls/day |  |  |  |  |  |  | $ | 1.45/gallon |  | $ | 1.60/gallon

(1) | 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.

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Every derivative instrument is required to be recorded on the balance sheet as either an asset or a liability measured at its fair value. We recognize all changes in fair value of these derivatives as earnings in derivative fair value income or loss in the periods in which they occur.

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. These contracts settle monthly through December 2024 and include a total volume of 204,967,500 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.

Divestiture Contingent Consideration

In addition to the derivatives described above, our right to receive contingent consideration in conjunction with the sale of our North Louisiana assets was determined to be a derivative financial instrument that is not designated as a hedging instrument. The remaining contingent consideration of up to $75.0 million is based on future achievement of natural gas and oil prices based on published indexes and realized NGLs prices of the buyer for the years 2021, 2022 and 2023. 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.

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 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 |
|  |  | Gross Amounts of Recognized Assets |  |  | Gross Amounts Offset in the Balance Sheet |  |  | Net Amounts of Assets Presented in the Balance Sheet |
Derivative assets: |  |  |  |  |  |  |  |  |  |
Natural gas | –swaps |  | $ | 5,574 |  |  | $ | (5,574 | ) |  | $ | — |
| –collars |  |  | 193 |  |  |  | (193 | ) |  |  | — |
| –three-way collars |  |  | 2 |  |  |  | (2 | ) |  |  | — |
| –basis swaps |  |  | 15,633 |  |  |  | (12,187 | ) |  |  | 3,446 |
Crude oil | –swaps |  |  | 10 |  |  |  | (10 | ) |  |  | — |
NGLs | –C3 propane spread swaps |  |  | 8,367 |  |  |  | (8,367 | ) |  |  | — |
| −C5 natural gasoline swaps |  |  | 17 |  |  |  | (17 | ) |  |  | — |
Freight | −swaps |  |  | 27 |  |  |  | (30 | ) |  |  | (3 | )
Divestiture contingent consideration |  |  | 50,220 |  |  |  | — |  |  |  | 50,220 |
|  |  | $ | 80,043 |  |  | $ | (26,380 | ) |  | $ | 53,663 |

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|  |  | September 30, 2021 |
|  |  | Gross Amounts of Recognized (Liabilities) |  |  | Gross Amounts Offset in the Balance Sheet |  |  | Net Amounts of (Liabilities) Presented in the Balance Sheet |
Derivative (liabilities): |  |  |  |  |  |  |  |  |  |
Natural gas | –swaps |  | $ | (359,243 | ) |  | $ | 5,574 |  |  | $ | (353,669 | )
| –swaptions |  |  | (60,132 | ) |  |  | — |  |  |  | (60,132 | )
| –collars |  |  | (93,418 | ) |  |  | 193 |  |  |  | (93,225 | )
| –three-way collars |  |  | (200,479 | ) |  |  | 2 |  |  |  | (200,477 | )
| –calls |  |  | (10,018 | ) |  |  | — |  |  |  | (10,018 | )
| –basis swaps |  |  | (7,160 | ) |  |  | 12,187 |  |  |  | 5,027 |
Crude oil | –swaps |  |  | (34,274 | ) |  |  | 10 |  |  |  | (34,264 | )
NGLs | –C3 propane spread swaps |  |  | (7,973 | ) |  |  | 8,367 |  |  |  | 394 |
| –C3 propane swaps |  |  | (6,140 | ) |  |  | — |  |  |  | (6,140 | )
| –C3 collars |  |  | (3,787 | ) |  |  | — |  |  |  | (3,787 | )
| –NC4 butane swaps |  |  | (3,991 | ) |  |  | — |  |  |  | (3,991 | )
| –NC4 butane collars |  |  | (2,797 | ) |  |  | — |  |  |  | (2,797 | )
| –C5 natural gasoline swaps |  |  | (3,908 | ) |  |  | 17 |  |  |  | (3,891 | )
| –C5 natural gasoline collars |  |  | (3,728 | ) |  |  | — |  |  |  | (3,728 | )
Freight | –swaps |  |  | (53 | ) |  |  | 30 |  |  |  | (23 | )
|  |  | $ | (797,101 | ) |  | $ | 26,380 |  |  | $ | (770,721 | )

|  |  | December 31, 2020 |
|  |  | Gross Amounts of Recognized Assets |  |  | Gross Amounts Offset in the Balance Sheet |  |  | Net Amounts of Assets Presented in the Balance Sheet |
Derivative assets: |  |  |  |  |  |  |  |  |  |
Natural gas | –swaps |  | $ | 33,559 |  |  | $ | (16,821 | ) |  | $ | 16,738 |
| –collars |  |  | 7,016 |  |  |  | (2,329 | ) |  |  | 4,687 |
| –three-way collars |  |  | 535 |  |  |  | (6,139 | ) |  |  | (5,604 | )
| –basis swaps |  |  | 7,894 |  |  |  | (3,502 | ) |  |  | 4,392 |
Crude oil | –swaps |  |  | 2,465 |  |  |  | (829 | ) |  |  | 1,636 |
NGLs | –C3 propane spread swaps |  |  | 4,863 |  |  |  | (4,863 | ) |  |  | — |
| –C3 propane collars |  |  | — |  |  |  | (107 | ) |  |  | (107 | )
Freight | –swaps |  |  | 2,310 |  |  |  | — |  |  |  | 2,310 |
Divestiture contingent consideration |  |  | 15,960 |  |  |  | — |  |  |  | 15,960 |
|  |  | $ | 74,602 |  |  | $ | (34,590 | ) |  | $ | 40,012 |

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|  |  | December 31, 2020 |
|  |  | Gross Amounts of Recognized (Liabilities) |  |  | Gross Amounts Offset in the Balance Sheet |  |  | Net Amounts of (Liabilities) Presented in the Balance Sheet |
Derivative (liabilities): |  |  |  |  |  |  |  |  |  |
Natural gas | –swaps |  | $ | (10,120 | ) |  | $ | 16,821 |  |  | $ | 6,701 |
| –swaptions |  |  | (9,803 | ) |  |  | — |  |  |  | (9,803 | )
| –collars |  |  | — |  |  |  | 2,329 |  |  |  | 2,329 |
| –three-way collars |  |  | (18,353 | ) |  |  | 6,139 |  |  |  | (12,214 | )
| –basis swaps |  |  | (4,197 | ) |  |  | 3,502 |  |  |  | (695 | )
Crude oil | –swaps |  |  | (5,471 | ) |  |  | 829 |  |  |  | (4,642 | )
NGLs | –C3 propane spread swaps |  |  | (4,069 | ) |  |  | 4,863 |  |  |  | 794 |
| –C3 propane swaps |  |  | (8,243 | ) |  |  | — |  |  |  | (8,243 | )
| –C3 propane collars |  |  | (3,086 | ) |  |  | 107 |  |  |  | (2,979 | )
| –C5 natural gasoline swaps |  |  | (4,897 | ) |  |  | — |  |  |  | (4,897 | )
| –C5 natural gasoline calls |  |  | (546 | ) |  |  | — |  |  |  | (546 | )
| –NC4 butane swaps |  |  | (651 | ) |  |  | — |  |  |  | (651 | )
| –NC4 butane collars |  |  | (401 | ) |  |  | — |  |  |  | (401 | )
Freight | –swaps |  |  | (1,206 | ) |  |  | — |  |  |  | (1,206 | )
|  |  | $ | (71,043 | ) |  | $ | 34,590 |  |  | $ | (36,453 | )

The effects of our derivatives on our consolidated statements of operations are summarized below (in thousands):

|  | Derivative Fair Value (Loss) Income |
|  | Three Months Ended September 30, |  |  | Nine Months Ended September 30, |
|  | 2021 |  |  | 2020 |  |  | 2021 |  |  | 2020 |
Commodity swaps |  | $ | (332,855 | ) |  | $ | (91,425 | ) |  | $ | (558,186 | ) |  | $ | 142,413 |
Swaptions |  |  | (33,718 | ) |  |  | (14,166 | ) |  |  | (50,329 | ) |  |  | (15,520 | )
Three-way collars |  |  | (173,344 | ) |  |  | (20,705 | ) |  |  | (226,176 | ) |  |  | (38,267 | )
Collars |  |  | (106,340 | ) |  |  | (16,893 | ) |  |  | (158,562 | ) |  |  | (14,336 | )
Calls |  |  | (10,018 | ) |  |  | (255 | ) |  |  | (10,793 | ) |  |  | (12 | )
Basis swaps |  |  | (8,469 | ) |  |  | 15,587 |  |  |  | 11,054 |  |  |  | 31,750 |
Freight swaps |  |  | (346 | ) |  |  | 2,737 |  |  |  | (1,050 | ) |  |  | (4,276 | )
Divestiture contingent consideration |  |  | 12,870 |  |  |  | 430 |  |  |  | 34,260 |  |  |  | 430 |
Total |  | $ | (652,220 | ) |  | $ | (124,690 | ) |  | $ | (959,782 | ) |  | $ | 102,182 |

(12) FAIR VALUE MEASUREMENTS

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. There are three approaches for measuring the fair value of assets and liabilities: the market approach, the income approach and the cost approach, each of which includes multiple valuation techniques. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. The income approach uses valuation techniques to measure fair value by converting future amounts, such as cash flows or earnings, into a single present value amount using current market expectations about those future amounts. The cost approach is based on the amount that would currently be required to replace the service capacity of an asset. This is often referred to as current replacement cost. The cost approach assumes that the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset of comparable utility, adjusted for obsolescence.

The fair value accounting standards do not prescribe which valuation technique should be used when measuring fair value and does not prioritize among the techniques. 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

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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. The three levels of the fair value hierarchy are as follows:


Level 1 – Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 – Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.

Level 3 – Unobservable inputs for which there is little, if any, market activity for the asset or liability being measured. These inputs reflect management’s best estimates of the assumptions market participants would use in determining fair value. Our Level 3 measurements consist of instruments using standard pricing models and other valuation methods that utilize unobservable pricing inputs that are significant to the overall fair value.

Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.

Significant uses of fair value measurements include:


impairment assessments of long-lived assets; and

recorded value of derivative instruments and trading securities.

The need to test long-lived assets can be based on several indicators, including a significant reduction in prices of natural gas, oil and condensate, NGLs, unfavorable adjustments to reserves, significant changes in the expected timing of production, other changes to contracts or changes in the regulatory environment in which a property is located.

Fair Values – Recurring

We use a market approach for our recurring fair value measurements and endeavor to use the best information available. 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: |
|  |  | Quoted Prices in Active Markets for Identical Assets (Level 1) |  |  | Significant Other Observable Inputs (Level 2) |  |  | Significant Unobservable Inputs (Level 3) |  |  | Total Carrying Value as of September 30, 2021 |
Trading securities held in the deferred compensation plans |  | $ | 66,833 |  |  | $ | — |  |  | $ | — |  |  | $ | 66,833 |
Commodity price derivatives | –swaps |  |  | — |  |  |  | (401,955 | ) |  |  | — |  |  |  | (401,955 | )
| –collars |  |  | — |  |  |  | (93,225 | ) |  |  | (10,312 | ) |  |  | (103,537 | )
| –three-way collars |  |  | — |  |  |  | (200,477 | ) |  |  | — |  |  |  | (200,477 | )
| –calls |  |  | — |  |  |  | (10,018 | ) |  |  |  |  |  | (10,018 | )
| –basis swaps |  |  | — |  |  |  | 8,867 |  |  |  | — |  |  |  | 8,867 |
| –swaptions |  |  | — |  |  |  | — |  |  |  | (60,132 | ) |  |  | (60,132 | )
Derivatives–freight swaps |  |  |  | — |  |  |  | (26 | ) |  |  | — |  |  |  | (26 | )
Divestiture contingent consideration |  |  | — |  |  |  | 50,220 |  |  |  | — |  |  |  | 50,220 |

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|  |  | Fair Value Measurements at December 31, 2020 using: |
|  |  | Quoted Prices in Active Markets for Identical Assets (Level 1) |  |  | Significant Other Observable Inputs (Level 2) |  |  | Significant Unobservable Inputs (Level 3) |  |  | Total Carrying Value as of December 31, 2020 |
Trading securities held in the deferred compensation plans |  | $ | 63,942 |  |  | $ | — |  |  | $ | — |  |  | $ | 63,942 |
Commodity price derivatives | –swaps |  |  | — |  |  |  | 6,642 |  |  |  | — |  |  |  | 6,642 |
| –calls |  |  | — |  |  |  | — |  |  |  | (546 | ) |  |  | (546 | )
| –collars |  |  | — |  |  |  | 7,016 |  |  |  | (3,487 | ) |  |  | 3,529 |
| –three-way collars |  |  | — |  |  |  | (17,818 | ) |  |  | — |  |  |  | (17,818 | )
| –basis swaps |  |  | — |  |  |  | 4,491 |  |  |  | — |  |  |  | 4,491 |
| –swaptions |  |  | — |  |  |  | — |  |  |  | (9,803 | ) |  |  | (9,803 | )
Derivatives–freight swaps |  |  |  | — |  |  |  | 1,104 |  |  |  | — |  |  |  | 1,104 |
Divesture contingent consideration |  |  | — |  |  |  | 15,960 |  |  |  | — |  |  |  | 15,960 |

Our trading securities in Level 1 are exchange-traded and measured at fair value with a market approach using end of period market values. 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. 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. 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. We also utilized a range of implied volatilities from 36% to 55% for our NGLs collars with a weighted average implied volatility of 42%. 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):

|  | As of September 30, 2021 |
Balance at December 31, 2020 |  | $ | (13,836 | )
Total losses: |  |  |
Included in earnings |  |  | (42,974 | )
Additions |  |  | (23,385 | )
Settlements |  |  | 5,177 |
Transfers out of Level 3 |  |  | 4,574 |
Balance at September 30, 2021 |  | $ | (70,444 | )

Divestiture Contingent Consideration. In August 2020, we completed the sale of our North Louisiana assets where we are entitled to receive contingent consideration based on future achievement of natural gas and oil prices based on published indexes along with NGLs prices based on the realized NGLs prices of the buyer. We used an option pricing model to estimate the fair value of the contingent consideration using significant Level 2 inputs that include quoted future commodity prices based on active markets.

Trading securities. Our trading securities held in the deferred compensation plan are accounted for using the mark-to- market accounting method and are included in other assets in the accompanying consolidated balance sheets. We elected to adopt the fair value option to simplify our accounting for the investments in our deferred compensation plan. 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.

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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.

Fair Values – Reported

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 |  |  | December 31, 2020 |
|  | Carrying Value |  |  | Fair Value |  |  | Carrying Value |  |  | Fair Value |
Assets: |  |  |  |  |  |  |  |  |  |  |  |
Commodity swaps, collars and basis swaps |  | $ | 3,443 |  |  | $ | 3,443 |  |  | $ | 24,052 |  |  | $ | 24,052 |
Divestiture contingent consideration |  |  | 50,220 |  |  |  | 50,220 |  |  |  | 15,960 |  |  |  | 15,960 |
Marketable securities (a) |  |  | 66,833 |  |  |  | 66,833 |  |  |  | 63,942 |  |  |  | 63,942 |
(Liabilities): |  |  |  |  |  |  |  |  |  |  |  |
Commodity swaps, collars and basis swaps |  |  | (770,721 | ) |  |  | (770,721 | ) |  |  | (36,453 | ) |  |  | (36,453 | )
Bank credit facility (b) |  |  | (30,000 | ) |  |  | (30,000 | ) |  |  | (702,000 | ) |  |  | (702,000 | )
5.75% senior notes due 2021 (b) |  |  | — |  |  |  | — |  |  |  | (25,496 | ) |  |  | (25,474 | )
5.00% senior notes due 2022 (b) |  |  | (169,589 | ) |  |  | (172,667 | ) |  |  | (169,589 | ) |  |  | (170,128 | )
5.875% senior notes due 2022 (b) |  |  | (48,528 | ) |  |  | (49,383 | ) |  |  | (48,528 | ) |  |  | (48,471 | )
Other senior notes due 2022 (b) |  |  | — |  |  |  | — |  |  |  | (490 | ) |  |  | (490 | )
5.00% senior notes due 2023 (b) |  |  | (532,335 | ) |  |  | (552,463 | ) |  |  | (532,335 | ) |  |  | (521,699 | )
4.875% senior notes due 2025 (b) |  |  | (750,000 | ) |  |  | (791,715 | ) |  |  | (750,000 | ) |  |  | (707,918 | )
9.25% senior notes due 2026 (b) |  |  | (850,000 | ) |  |  | (926,832 | ) |  |  | (850,000 | ) |  |  | (888,208 | )
8.25% senior notes due 2029 (b) |  |  | (600,000 | ) |  |  | (674,994 | ) |  |  | — |  |  |  | — |
5.75% senior subordinated notes due 2021 (b) |  |  | — |  |  |  | — |  |  |  | (19,896 | ) |  |  | (19,589 | )
5.00% senior subordinated notes due 2022 (b) |  |  | — |  |  |  | — |  |  |  | (9,730 | ) |  |  | (9,247 | )
5.00% senior subordinated notes due 2023 (b) |  |  | — |  |  |  | — |  |  |  | (7,712 | ) |  |  | (6,604 | )
Deferred compensation plan (c) |  |  | (184,882 | ) |  |  | (184,882 | ) |  |  | (96,563 | ) |  |  | (96,563 | )

(a) | Marketable securities, which are held in our deferred compensation plans, are actively traded on major exchanges.
(b) | 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.
(c) | 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.

Our current assets and liabilities include financial instruments, the most significant of which are trade accounts receivable and payable. We believe the carrying values of our current assets and liabilities approximate fair value. Our fair value assessment incorporates a variety of considerations, including (1) the short-term duration of the instruments and (2) our historical and expected incurrence of bad debt expense. Non-financial liabilities initially measured at fair value include asset retirement obligations, operating lease liabilities and the divestiture contract obligation that we incurred in conjunction with the sale of our North Louisiana assets.

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. 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 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. To manage counterparty risk associated with our derivatives, we select and monitor our counterparties based on our assessment of their financial strength and/or credit ratings. 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

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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.

Allowance for Expected Credit Losses. Each reporting period, we assess the recoverability of material receivables using historical data, current market conditions and reasonable and supported forecasts of future economic conditions to determine their expected collectability. The loss given default method is used when, based on management’s judgment, an allowance for expected credit losses should be accrued on a material receivable to reflect the net amount to be collected.

(13) STOCK-BASED COMPENSATION PLANS

Stock-Based Awards

We have two active equity-based stock plans: our Amended and Restated 2005 Equity-Based Incentive Compensation Plan and our Amended and Restated 2019 Equity-Based Compensation Plan. Under these plans, various awards may be issued to non-employee directors and employees pursuant to decisions of the Compensation Committee, which is composed of only non-employee, independent directors.

Total Stock-Based Compensation Expense

Stock-based compensation represents amortization of restricted stock and performance units. Unlike the other forms of stock-based compensation, the mark-to-market adjustment of the liability related to the vested restricted stock held in our deferred compensation plan is directly tied to the change in our stock price and not directly related to the functional expenses and therefore, is not allocated to the functional categories. The following details the allocation of stock-based compensation to functional expense categories (in thousands):

|  | Three Months Ended September 30, |  |  | Nine Months Ended September 30, |
|  | 2021 |  |  | 2020 |  |  | 2021 |  |  | 2020 |
Direct operating expense |  | $ | 319 |  |  | $ | (74 | ) |  | $ | 986 |  |  | $ | 810 |
Brokered natural gas and marketing expense |  |  | 446 |  |  |  | 324 |  |  |  | 1,339 |  |  |  | 905 |
Exploration expense |  |  | 368 |  |  |  | 189 |  |  |  | 1,116 |  |  |  | 891 |
General and administrative expense |  |  | 9,845 |  |  |  | 6,863 |  |  |  | 28,632 |  |  |  | 24,071 |
Termination costs |  |  | — |  |  |  | 2,020 |  |  |  | — |  |  |  | 2,020 |
Total stock-based compensation expense |  | $ | 10,978 |  |  | $ | 9,322 |  |  | $ | 32,073 |  |  | $ | 28,697 |

Stock-Based Awards

Restricted Stock Awards. We grant restricted stock units under our equity-based stock compensation plans. These restricted stock units, which we refer to as restricted stock Equity Awards, generally vest over a three-year period, contingent on the recipient’s continued employment. The grant date fair value of the Equity Awards is based on the fair market value of our common stock on the date of grant.

The Compensation Committee also grants restricted stock to certain employees and non-employee directors of the Board of Directors as part of their compensation. We also grant restricted stock to certain employees for retention purposes. Compensation expense is recognized over the balance of the vesting period, which is typically three years for employee grants and one year vesting for non-employee directors. All restricted stock awards are issued at prevailing market prices at the time of the grant and the vesting is based upon an employee’s continued employment with us. Prior to vesting, all restricted stock award recipients have the right to vote such stock and receive dividends thereon. Upon grant of these restricted shares, which we refer to as restricted stock Liability Awards, the majority of these shares are generally placed in our deferred compensation plan and, upon vesting, withdrawals are allowed in either cash or in stock. In early 2021, vesting for new grants of restricted stock Liability Awards changed to a three-year cliff vesting from a ratable 30%-30%-40% vesting schedule. These Liability Awards are classified as a liability and are remeasured at fair value each reporting period. This mark-to-market amount is reported in deferred compensation plan expense in the accompanying consolidated statements of operations. Historically, we have used authorized but unissued shares of stock when restricted stock is granted. However, we can also utilize treasury shares when available.

Stock-Based Performance Units. 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). 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

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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.

Each unit granted represents one share of our common stock. These units are settled in stock and the amount of the payout is based on (1) the vesting percentage, which can range from zero to 200% based on performance achieved, which is determined by the Compensation Committee and (2) the value of our common stock on the vesting date. 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.

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. Restricted stock Equity Awards are not issued to employees until such time as they are vested. Employees do not have the option to receive cash.

Restricted Stock – 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. 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:

|  | Restricted Stock Equity Awards |  |  | Restricted Stock Liability Awards |
|  | Shares |  |  | Weighted Average Grant Date Fair Value |  |  | Shares |  |  | Weighted Average Grant Date Fair Value |
Outstanding at December 31, 2020 |  |  | 2,815,860 |  |  | $ | 4.97 |  |  |  | 1,186,636 |  |  | $ | 4.18 |
Granted |  |  | 2,340,114 |  |  |  | 10.20 |  |  |  | 1,288,729 |  |  |  | 9.55 |
Vested |  |  | (1,820,011 | ) |  |  | 7.37 |  |  |  | (1,316,542 | ) |  |  | 6.98 |
Forfeited |  |  | (79,732 | ) |  |  | 6.30 |  |  |  | — |  |  |  | — |
Outstanding at September 30, 2021 |  |  | 3,256,231 |  |  | $ | 7.36 |  |  |  | 1,158,823 |  |  | $ | 6.98 |

Stock-Based Performance Units

Internal Performance Metric Awards. These awards vest at the end of the three-year performance period. The performance metrics are set by the Compensation Committee. 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:

|  | Number of Units |  |  | Weighted Average Grant Date Fair Value |
Outstanding at December 31, 2020 |  |  | 1,099,102 |  |  | $ | 5.92 |
Units granted (a) |  |  | 303,231 |  |  |  | 9.81 |
Vested and issued (b) |  |  | (306,978 | ) |  |  | 12.20 |
Forfeited |  |  | — |  |  |  | — |
Outstanding at September 30, 2021 |  |  | 1,095,355 |  |  | $ | 7.80 |

(a) | Amounts granted reflect the number of performance units granted; however, the actual payout of shares will be between zero and 200% depending on achievement of specifically identified performance targets. Units granted in first quarter 2021 were to our CEO, CFO and COO only.
(b) | 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.

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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.

TSR Awards. 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. The fair value of the TSR-PSUs is estimated on the date of grant using a Monte Carlo simulation model which utilizes multiple input variables that determine the probability of satisfying the market condition stipulated in the award grant and calculates the fair value of the award. The fair value is recognized as stock-based compensation expense over the three-year performance period. Expected volatilities utilized in the model were estimated using a combination of a historical period consistent with the remaining performance period of three years and option implied volatilities. 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, |
|  | 2021 |  |  | 2020 |
Risk-free interest rate |  |  | 0.2 | % |  |  | 1.4 | %
Expected annual volatility |  |  | 75 | % |  |  | 65 | %
Grant date fair value per unit |  | $ | 12.58 |  |  | $ | 3.85 |

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

|  | Number of Units |  |  | Weighted Average Grant Date Fair Value |
Outstanding at December 31, 2020 |  |  | 1,249,524 |  |  | $ | 9.55 |
Units granted (a) |  |  | 223,687 |  |  |  | 12.58 |
Vested and issued (b) |  |  | (325,217 | ) |  |  | 18.51 |
Forfeited |  |  | — |  |  |  | — |
Outstanding at September 30, 2021 |  |  | 1,147,994 |  |  | $ | 7.60 |

(a) | 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.
(b) | 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. Fair value is amortized over the performance period with no adjustment to the expense recorded for actual targets achieved.

Other Post Retirement Benefits

Effective fourth quarter 2017, as part of our officer succession plan, we implemented a post retirement benefit plan to assist in providing health care to officers who are active employees (including their spouses) and have met certain age and service requirements. 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. 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.

Deferred Compensation Plan

Our deferred compensation plan gives non-employee directors and officers the ability to defer all or a portion of their salaries, bonuses or director fees and invest in Range common stock or make other investments at the individual’s discretion. Range provides a partial matching contribution to officers which vests over three years. In early 2021, vesting for the matching contribution was changed to a three-year cliff vesting schedule. The assets of the plan are held in a grantor trust, which we refer to as the Rabbi Trust, and are therefore available to satisfy the claims of our general creditors in the event of bankruptcy or insolvency. 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. 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

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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. The deferred compensation liability reflects the vested market value of the marketable securities and Range stock held in the Rabbi Trust. 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.

(14) EXIT AND TERMINATION COSTS

Exit Costs

In August 2020, we sold our North Louisiana assets and retained certain gathering, transportation and processing obligations which extend into 2030. These are contracts where we will not realize any future benefit. 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 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.

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):

|  | Three Months Ended September 30, |  |  | Nine Months Ended September 30, |
|  | 2021 |  |  | 2020 |  |  | 2021 |  |  | 2020 |
Severance costs |  | $ | — |  |  | $ | 4,191 |  |  | $ | 509 |  |  | $ | 5,638 |
Transportation contract capacity releases (including accretion of discount) |  |  | 186 |  |  |  | 233 |  |  |  | 580 |  |  |  | 10,678 |
Divestiture contract obligation (including accretion of discount) |  |  | 11,603 |  |  |  | 486,689 |  |  |  | 8,468 |  |  |  | 486,689 |
One-time minimum volume commitment contract payment |  |  | — |  |  |  | 28,500 |  |  |  | — |  |  |  | 28,500 |
Stock-based compensation |  |  | — |  |  |  | 2,020 |  |  |  | — |  |  |  | 2,020 |
|  | $ | 11,789 |  |  | $ | 521,633 |  |  | $ | 9,557 |  |  | $ | 533,525 |

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

|  | Exit Costs (1) |  |  | Termination Costs |
Balance at December 31, 2020 |  | $ | 493,543 |  |  | $ | 1,454 |
Accrued severance costs |  |  | — |  |  |  | 509 |
Accretion of discount |  |  | 37,213 |  |  |  | — |
Divestiture contract obligation - changes in estimate |  |  | (28,165 | ) |  |  | — |
Payments |  |  | (68,152 | ) |  |  | (1,695 | )
Balance at September 30, 2021 |  | $ | 434,439 |  |  | $ | 268 |

(1) | Includes the divestiture contract obligation and the transportation contract capacity release obligation.

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(15) CAPITAL STOCK

We have authorized capital stock of 485.0 million shares which includes 475.0 million shares of common stock and 10.0 million shares of preferred stock. We currently have no preferred stock issued or outstanding. The following is a schedule of changes in the number of common shares outstanding since the beginning of 2020:

|  | Nine Months Ended September 30, 2021 |  |  | Year Ended December 31, 2020 |
Beginning balance |  |  | 246,348,092 |  |  |  | 249,630,803 |
Restricted stock grants |  |  | 1,293,126 |  |  |  | 3,390,358 |
Restricted stock units vested |  |  | 1,485,557 |  |  |  | 1,226,473 |
Performance stock units issued |  |  | 640,468 |  |  |  | 279,420 |
Performance stock dividends |  |  | 13,966 |  |  |  | 18,700 |
Treasury shares |  |  | 3,149 |  |  |  | (8,197,662 | )
Ending balance |  |  | 249,784,358 |  |  |  | 246,348,092 |

Stock Repurchase Program

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

|  | Three Months Ended September 30, 2021 |  |  | Nine Months Ended September 30, 2021 |
Beginning balance |  |  | 10,005,504 |  |  |  | 10,005,795 |
Rabbi trust shares distributed/sold |  |  | (2,858 | ) |  |  | (3,149 | )
Shares repurchased |  |  | — |  |  |  | — |
Ending balance |  |  | 10,002,646 |  |  |  | 10,002,646 |

(16) SUPPLEMENTAL CASH FLOW INFORMATION

|  | Nine Months Ended September 30, |
|  | 2021 |  |  | 2020 |
|  | (in thousands) |
Net cash provided from operating activities included: |  |  |  |  |  |
Income taxes (paid) refunded from taxing authorities |  | $ | (2,661 | ) |  | $ | 343 |
Interest paid |  |  | (175,195 | ) |  |  | (145,319 | )
Non-cash investing and financing activities included: |  |  |  |  |  |
Increase in asset retirement costs capitalized |  |  | 2,879 |  |  |  | 4,587 |
Decrease in accrued capital expenditures |  |  | (11,373 | ) |  |  | (38,942 | )

(17) COMMITMENTS AND CONTINGENCIES

Litigation

We are the subject of, or party to, a number of pending or threatened legal actions, administrative proceedings or investigations arising in the ordinary course of our business including, but not limited to, royalty claims, contract claims and environmental claims. While many of these matters involve inherent uncertainty, we believe that the amount of the liability, if any, ultimately incurred with respect to these actions, proceedings or claims will not have a material adverse effect on our consolidated financial position as a whole or on our liquidity, capital resources or future annual results of operations.

When deemed necessary, we establish reserves for certain legal proceedings. The establishment of a reserve is based on an estimation process that includes the advice of legal counsel and subjective judgment of management. While management believes these reserves to be adequate, it is reasonably possible we could incur additional losses with respect to those matters in which reserves have been established. We will continue to evaluate our litigation on a quarterly basis and will establish and adjust any litigation reserves as appropriate to reflect our assessment of the then current status of litigation.

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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. 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. 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):

|  | 2021 |
Balance at beginning of period |  | $ | 7,709 |
Additions to capitalized exploratory well costs pending the determination of proved reserves |  |  | 6,299 |
Reclassifications to wells, facilities and equipment based on determination of proved reserves |  |  | (14,008 | )
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 |  | $ | — |

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

|  | Nine Months Ended September 30, 2021 |  |  | Year Ended December 31, 2020 |
|  | (in thousands) |
Acquisitions: |  |  |  |  |  |
Acreage purchases |  | $ | 14,014 |  |  | $ | 26,166 |
Development |  |  | 298,300 |  |  |  | 369,093 |
Exploration: |  |  |  |  |  |
Drilling |  |  | 6,299 |  |  |  | 7,709 |
Expense |  |  | 15,331 |  |  |  | 31,376 |
Stock-based compensation expense |  |  | 1,116 |  |  |  | 1,279 |
Gas gathering facilities: |  |  |  |  |  |
Development |  |  | 2,846 |  |  |  | 3,694 |
Subtotal |  |  | 337,906 |  |  |  | 439,317 |
Asset retirement obligations |  |  | 2,879 |  |  |  | 2,610 |
Total costs incurred |  | $ | 340,785 |  |  | $ | 441,927 |

(a) | Includes costs incurred whether capitalized or expensed.

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ITE M 2. MANAGEMENT’S DISCUSSION AND ANA LYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Overview of Our Business

We are a Fort Worth, Texas-based independent natural gas, natural gas liquids (NGLs) and oil company primarily engaged in the exploration, development and acquisition of natural gas properties in the Appalachian region of the United States. We operate in one segment and have a single company-wide management team that administers all properties as a whole rather than by discrete operating segments. We measure financial performance as a single enterprise and not on a geographical or an area-by-area basis.

Our overarching business objective is to build stockholder value through returns-focused development of natural gas properties. Our strategy to achieve our business objective is to generate consistent cash flows from reserves and production through internally generated drilling projects occasionally coupled with complementary acquisitions and divestitures of non-core or, at times, core assets. 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. Commodity prices have been and are expected to remain volatile. Our primary near-term focus includes the following:


operate safely and efficiently;

target capital spending at or below operating cash flow;

reduce emissions and target net zero direct greenhouse gas emissions by 2025;

achieve competitive returns on investments;

manage liquidity and further improve financial strength;

focus on organic opportunities through disciplined capital investments;

improve operational efficiencies and economic returns;

attract and retain quality employees; and

align employee incentives with our stockholders’ interests and key business objectives.

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

Prices for natural gas, NGLs and oil fluctuate widely and affect:


revenues, profitability and cash flow;

the quantity of natural gas, NGLs and oil we can economically produce;

the quantity of natural gas, NGLs and oil shown as proved reserves;

the amount of cash flows available for capital expenditures; and

our ability to borrow and raise additional capital.

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the preceding consolidated financial statements and notes in Item 1.

Market Conditions

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

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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:

|  | Three Months Ended September 30, |  |  | Nine Months Ended September 30, |
|  | 2021 |  |  | 2020 |  |  | 2021 |  |  | 2020 |
Benchmarks: |  |  |  |  |  |  |  |  |  |  |  |
Average NYMEX prices (a) |  |  |  |  |  |  |  |  |  |  |  |
Natural gas (per mcf) |  | $ | 4.01 |  |  | $ | 1.95 |  |  | $ | 3.19 |  |  | $ | 1.87 |
Oil (per bbl) |  |  | 70.42 |  |  |  | 40.90 |  |  |  | 64.70 |  |  |  | 38.87 |
Mont Belvieu NGLs composite (per gallon) (b) |  |  | 0.82 |  |  |  | 0.40 |  |  |  | 0.69 |  |  |  | 0.35 |

(a) | Based on weighted average of bid week prompt month prices on the New York Mercantile Exchange (“NYMEX”).
(b) | Based on our estimated NGLs product composition per barrel.

Our price realizations (not including the impact of our derivatives) may differ from these benchmarks for many reasons, including quality, location or production being sold at different indices.

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;

revenue from the sale of natural gas, NGLs and oil (including cash settlements on our derivatives) increased 48% from the same period of 2020;

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; and

reduced depletion, depreciation and amortization (“DD&A”) rate per mcfe by 2% from the same period of 2020.

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

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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; and

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.

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

Our revenues vary primarily as a result of changes in realized commodity prices and production volumes. 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):

|  | Three Months Ended September 30, |  |  | Nine Months Ended September 30, |
|  | 2021 |  |  | 2020 |  |  | Change |  |  | % |  |  | 2021 |  |  | 2020 |  |  | Change |  |  | % |
Natural gas, NGLs and oil sales |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Natural gas |  | $ | 494,917 |  |  | $ | 211,638 |  |  | $ | 283,279 |  |  |  | 134 | % |  | $ | 1,152,283 |  |  | $ | 679,094 |  |  | $ | 473,189 |  |  |  | 70 | %
NGLs |  |  | 309,232 |  |  |  | 149,263 |  |  |  | 159,969 |  |  |  | 107 | % |  |  | 795,173 |  |  |  | 416,885 |  |  |  | 378,288 |  |  |  | 91 | %
Oil |  |  | 45,156 |  |  |  | 20,652 |  |  |  | 24,504 |  |  |  | 119 | % |  |  | 127,051 |  |  |  | 66,928 |  |  |  | 60,123 |  |  |  | 90 | %
Total natural gas, NGLs and oil sales |  | $ | 849,305 |  |  | $ | 381,553 |  |  | $ | 467,752 |  |  |  | 123 | % |  | $ | 2,074,507 |  |  | $ | 1,162,907 |  |  | $ | 911,600 |  |  |  | 78 | %

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:

29

|  | Three Months Ended September 30, |  |  | Nine Months Ended September 30, |
|  | 2021 |  |  | 2020 |  |  | Change |  |  | % |  |  | 2021 |  |  | 2020 |  |  | Change |  |  | % |
Production (a) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Natural gas (mcf) |  |  | 137,713,717 |  |  |  | 142,876,351 |  |  |  | (5,162,634 | ) |  |  | (4 | )% |  |  | 399,929,389 |  |  |  | 439,764,525 |  |  |  | (39,835,136 | ) |  |  | (9 | )%
NGLs (bbls) |  |  | 9,080,902 |  |  |  | 9,176,553 |  |  |  | (95,651 | ) |  |  | (1 | )% |  |  | 26,977,257 |  |  |  | 28,525,849 |  |  |  | (1,548,592 | ) |  |  | (5 | )%
Crude oil (bbls) |  |  | 710,914 |  |  |  | 656,319 |  |  |  | 54,595 |  |  |  | 8 | % |  |  | 2,245,972 |  |  |  | 2,244,741 |  |  |  | 1,231 |  |  |  | — | %
Total (mcfe) (b) |  |  | 196,464,613 |  |  |  | 201,873,583 |  |  |  | (5,408,970 | ) |  |  | (3 | )% |  |  | 575,268,763 |  |  |  | 624,388,065 |  |  |  | (49,119,302 | ) |  |  | (8 | )%
Average daily production (a) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Natural gas (mcf) |  |  | 1,496,888 |  |  |  | 1,553,004 |  |  |  | (56,116 | ) |  |  | (4 | )% |  |  | 1,464,943 |  |  |  | 1,604,980 |  |  |  | (140,037 | ) |  |  | (9 | )%
NGLs (bbls) |  |  | 98,705 |  |  |  | 99,745 |  |  |  | (1,040 | ) |  |  | (1 | )% |  |  | 98,818 |  |  |  | 104,109 |  |  |  | (5,291 | ) |  |  | (5 | )%
Crude oil (bbls) |  |  | 7,727 |  |  |  | 7,134 |  |  |  | 593 |  |  |  | 8 | % |  |  | 8,227 |  |  |  | 8,192 |  |  |  | 35 |  |  |  | — | %
Total (mcfe) (b) |  |  | 2,135,485 |  |  |  | 2,194,278 |  |  |  | (58,793 | ) |  |  | (3 | )% |  |  | 2,107,212 |  |  |  | 2,278,789 |  |  |  | (171,577 | ) |  |  | (8 | )%

(a) | Represents volumes sold regardless of when produced.
(b) | 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. We believe computed final realized prices should include the total impact of transportation, gathering, processing and compression expense. Our average realized price (including all derivative settlements and third-party transportation costs) calculation also includes all cash settlements for derivatives. Average realized prices (excluding derivative settlements) do not include derivative settlements or third-party transportation costs which are reported in transportation, gathering, processing and compression expense in the accompanying consolidated statements of operations. 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:

| Three Months Ended September 30, |  |  | Nine Months Ended September 30, |
| 2021 |  |  | 2020 |  |  | Change |  |  | % |  |  | 2021 |  |  | 2020 |  |  | Change |  |  | % |
Average Prices |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Average realized prices (excluding derivative settlements): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Natural gas (per mcf) | $ | 3.59 |  |  | $ | 1.48 |  |  | $ | 2.11 |  |  |  | 143 | % |  | $ | 2.88 |  |  | $ | 1.54 |  |  | $ | 1.34 |  |  |  | 87 | %
NGLs (per bbl) |  | 34.05 |  |  |  | 16.27 |  |  |  | 17.78 |  |  |  | 109 | % |  |  | 29.48 |  |  |  | 14.61 |  |  |  | 14.87 |  |  |  | 102 | %
Crude oil and condensate (per bbl) |  | 63.52 |  |  |  | 31.47 |  |  |  | 32.05 |  |  |  | 102 | % |  |  | 56.57 |  |  |  | 29.82 |  |  |  | 26.75 |  |  |  | 90 | %
Total (per mcfe) (a) |  | 4.32 |  |  |  | 1.89 |  |  |  | 2.43 |  |  |  | 129 | % |  |  | 3.61 |  |  |  | 1.86 |  |  |  | 1.75 |  |  |  | 94 | %
Average realized prices (including all derivative settlements): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Natural gas (per mcf) | $ | 2.69 |  |  | $ | 2.00 |  |  | $ | 0.69 |  |  |  | 35 | % |  | $ | 2.55 |  |  | $ | 2.10 |  |  | $ | 0.45 |  |  |  | 21 | %
NGLs (per bbl) |  | 31.17 |  |  |  | 16.17 |  |  |  | 15.00 |  |  |  | 93 | % |  |  | 26.59 |  |  |  | 15.18 |  |  |  | 11.41 |  |  |  | 75 | %
Crude oil and condensate (per bbl) |  | 50.32 |  |  |  | 50.81 |  |  |  | (0.49 | ) |  |  | (1 | )% |  |  | 43.89 |  |  |  | 49.49 |  |  |  | (5.60 | ) |  |  | (11 | )%
Total (per mcfe) (a) |  | 3.51 |  |  |  | 2.32 |  |  |  | 1.19 |  |  |  | 51 | % |  |  | 3.19 |  |  |  | 2.35 |  |  |  | 0.84 |  |  |  | 36 | %
Average realized prices (including all derivative settlements and third-party transportation costs paid by Range): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Natural gas (per mcf) | $ | 1.49 |  |  | $ | 0.90 |  |  | $ | 0.59 |  |  |  | 66 | % |  | $ | 1.33 |  |  | $ | 0.98 |  |  | $ | 0.35 |  |  |  | 36 | %
NGLs (per bbl) |  | 16.83 |  |  |  | 4.09 |  |  |  | 12.74 |  |  |  | 311 | % |  |  | 13.00 |  |  |  | 3.38 |  |  |  | 9.62 |  |  |  | 285 | %
Crude oil and condensate (per bbl) |  | 49.72 |  |  |  | 50.56 |  |  |  | (0.84 | ) |  |  | (2 | )% |  |  | 43.50 |  |  |  | 49.07 |  |  |  | (5.57 | ) |  |  | (11 | )%
Total (per mcfe) (a) |  | 2.00 |  |  |  | 0.99 |  |  |  | 1.01 |  |  |  | 102 | % |  |  | 1.71 |  |  |  | 1.02 |  |  |  | 0.69 |  |  |  | 68 | %

(1) | 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.

Realized prices include the impact of basis differentials and gains or losses realized from our basis hedging. The prices we receive for our natural gas can be more or less than the NYMEX price because of adjustments for delivery location, relative quality and other factors. The following table provides this impact on a per mcf basis:

30

|  | Three Months Ended September 30, |  |  | Nine Months Ended September 30, |
|  | 2021 |  |  | 2020 |  |  | 2021 |  |  | 2020 |
Average natural gas differentials below NYMEX |  | $ | (0.42 | ) |  | $ | (0.47 | ) |  | $ | (0.31 | ) |  | $ | (0.33 | )
Realized gains on basis hedging |  | $ | 0.06 |  |  | $ | 0.05 |  |  | $ | 0.02 |  |  | $ | 0.04 |

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, |
|  | 2020 |  |  | Price Variance |  |  | Volume Variance |  |  | 2021 |  |  | 2020 |  |  | Price Variance |  |  | Volume Variance |  |  | 2021 |
Natural gas |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Price (per mcf) |  | $ | 1.48 |  |  | $ | 2.11 |  |  | $ | — |  |  | $ | 3.59 |  |  | $ | 1.54 |  |  | $ | 1.34 |  |  | $ | — |  |  | $ | 2.88 |
Production (Mmcf) |  |  | 142,876 |  |  |  | — |  |  |  | (5,162 | ) |  |  | 137,714 |  |  |  | 439,765 |  |  |  | — |  |  |  | (39,836 | ) |  |  | 399,929 |
Natural gas sales |  | $ | 211,638 |  |  | $ | 290,926 |  |  | $ | (7,647 | ) |  | $ | 494,917 |  |  | $ | 679,094 |  |  | $ | 534,703 |  |  | $ | (61,514 | ) |  | $ | 1,152,283 |

|  | Three Months Ended September 30, |  |  | Nine Months Ended September 30, |
|  | 2020 |  |  | Price Variance |  |  | Volume Variance |  |  | 2021 |  |  | 2020 |  |  | Price Variance |  |  | Volume Variance |  |  | 2021 |
NGLs |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Price (per bbl) |  | $ | 16.27 |  |  | $ | 17.78 |  |  | $ | — |  |  | $ | 34.05 |  |  | $ | 14.61 |  |  | $ | 14.87 |  |  | $ | — |  |  | $ | 29.48 |
Production (Mbbls) |  |  | 9,177 |  |  |  | — |  |  |  | (96 | ) |  |  | 9,081 |  |  |  | 28,526 |  |  |  | — |  |  |  | (1,549 | ) |  |  | 26,977 |
NGLs sales |  | $ | 149,263 |  |  | $ | 161,525 |  |  | $ | (1,556 | ) |  | $ | 309,232 |  |  | $ | 416,885 |  |  | $ | 400,920 |  |  | $ | (22,632 | ) |  | $ | 795,173 |

|  | Three Months Ended September 30, |  |  | Nine Months Ended September 30, |
|  | 2020 |  |  | Price Variance |  |  | Volume Variance |  |  | 2021 |  |  | 2020 |  |  | Price Variance |  |  | Volume Variance |  |  | 2021 |
Crude oil |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Price (per bbl) |  | $ | 31.47 |  |  | $ | 32.05 |  |  | $ | — |  |  | $ | 63.52 |  |  | $ | 29.82 |  |  | $ | 26.75 |  |  | $ | — |  |  | $ | 56.57 |
Production (Mbbls) |  |  | 656 |  |  |  | — |  |  |  | 55 |  |  |  | 711 |  |  |  | 2,245 |  |  |  | — |  |  |  | 1 |  |  |  | 2,246 |
Crude oil sales |  | $ | 20,652 |  |  | $ | 22,786 |  |  | $ | 1,718 |  |  | $ | 45,156 |  |  | $ | 66,928 |  |  | $ | 60,086 |  |  | $ | 37 |  |  | $ | 127,051 |

|  | Three Months Ended September 30, |  |  | Nine Months Ended September 30, |
|  | 2020 |  |  | Price Variance |  |  | Volume Variance |  |  | 2021 |  |  | 2020 |  |  | Price Variance |  |  | Volume Variance |  |  | 2021 |
Consolidated |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Price (per mcfe) |  | $ | 1.89 |  |  | $ | 2.43 |  |  | $ | — |  |  | $ | 4.32 |  |  | $ | 1.86 |  |  | $ | 1.75 |  |  | $ | — |  |  | $ | 3.61 |
Production (Mmcfe) |  |  | 201,874 |  |  |  | — |  |  |  | (5,409 | ) |  |  | 196,465 |  |  |  | 624,388 |  |  |  | — |  |  |  | (49,119 | ) |  |  | 575,269 |
Total natural gas, NGLs and oil sales |  | $ | 381,553 |  |  | $ | 477,975 |  |  | $ | (10,223 | ) |  | $ | 849,305 |  |  | $ | 1,162,907 |  |  | $ | 1,003,083 |  |  | $ | (91,483 | ) |  | $ | 2,074,507 |

31

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. 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):

|  | Three Months Ended September 30, |  |  | Nine Months Ended September 30, |
|  | 2021 |  |  | 2020 |  |  | Change |  |  | % |  |  | 2021 |  |  | 2020 |  |  | Change |  |  | % |
Transportation, gathering, processing and compression |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Natural gas |  | $ | 165,864 |  |  | $ | 157,097 |  |  | $ | 8,767 |  |  |  | 6 | % |  | $ | 486,162 |  |  | $ | 494,305 |  |  | $ | (8,143 | ) |  |  | (2 | )%
NGLs |  |  | 130,221 |  |  |  | 110,849 |  |  |  | 19,372 |  |  |  | 17 | % |  |  | 366,648 |  |  |  | 336,491 |  |  |  | 30,157 |  |  |  | 9 | %
Oil |  |  | 425 |  |  |  | 162 |  |  |  | 263 |  |  |  | 162 | % |  |  | 874 |  |  |  | 952 |  |  |  | (78 | ) |  |  | (8 | )%
Total |  | $ | 296,510 |  |  | $ | 268,108 |  |  | $ | 28,402 |  |  |  | 11 | % |  | $ | 853,684 |  |  | $ | 831,748 |  |  | $ | 21,936 |  |  |  | 3 | %
Natural gas (per mcf) |  | $ | 1.20 |  |  | $ | 1.10 |  |  | $ | 0.10 |  |  |  | 9 | % |  | $ | 1.22 |  |  | $ | 1.12 |  |  | $ | 0.10 |  |  |  | 9 | %
NGLs (per bbl) |  | $ | 14.34 |  |  | $ | 12.08 |  |  | $ | 2.26 |  |  |  | 19 | % |  | $ | 13.59 |  |  | $ | 11.80 |  |  | $ | 1.79 |  |  |  | 15 | %
Oil (per bbl) |  | $ | 0.60 |  |  | $ | 0.25 |  |  | $ | 0.35 |  |  |  | 140 | % |  | $ | 0.39 |  |  | $ | 0.42 |  |  | $ | (0.03 | ) |  |  | (7 | )%

32

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. All of our derivatives are accounted for using the mark-to-market accounting method. Mark-to-market accounting treatment can result in more volatility of our revenues as the change in the fair value of our commodity derivative positions is included in total revenue. As commodity prices increase or decrease, such changes will have an opposite effect on the mark-to-market value of our derivatives. 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):

|  | Three Months Ended September 30, |  |  | Nine Months Ended September 30, |
|  | 2021 |  |  | 2020 |  |  | 2021 |  |  | 2020 |
Derivative fair value (loss) income per consolidated statements of operations |  | $ | (652,220 | ) |  | $ | (124,690 | ) |  | $ | (959,782 | ) |  | $ | 102,182 |
Non-cash fair value (loss) gain: (1) |  |  |  |  |  |  |  |  |  |  |  |
Natural gas derivatives |  | $ | (503,633 | ) |  | $ | (197,028 | ) |  | $ | (715,578 | ) |  | $ | (231,805 | )
Oil derivatives |  |  | (1,696 | ) |  |  | (15,145 | ) |  |  | (31,259 | ) |  |  | 17,589 |
NGLs derivatives |  |  | (241 | ) |  |  | (2,329 | ) |  |  | (6,910 | ) |  |  | 13,642 |
Freight derivatives |  |  | (63 | ) |  |  | 3,568 |  |  |  | (1,130 | ) |  |  | (2,917 | )
Divestiture contingent consideration |  |  | 12,870 |  |  |  | 430 |  |  |  | 34,260 |  |  |  | 430 |
Total non-cash fair value (loss) gain (1) |  | $ | (492,763 | ) |  | $ | (210,504 | ) |  | $ | (720,617 | ) |  | $ | (203,061 | )
Net cash (payment) receipt on derivative settlements: |  |  |  |  |  |  |  |  |  |  |  |
Natural gas derivatives |  | $ | (123,932 | ) |  | $ | 74,035 |  |  | $ | (132,794 | ) |  | $ | 245,044 |
Oil derivatives |  |  | (9,383 | ) |  |  | 12,694 |  |  |  | (28,472 | ) |  |  | 44,166 |
NGLs derivatives |  |  | (26,142 | ) |  |  | (915 | ) |  |  | (77,899 | ) |  |  | 16,033 |
Total net cash (payment) receipt |  | $ | (159,457 | ) |  | $ | 85,814 |  |  | $ | (239,165 | ) |  | $ | 305,243 |

(1) | Non-cash fair value adjustments on commodity derivatives is a non-U.S. GAAP measure. Non-cash fair value adjustments on commodity derivatives only represent the net change between periods of the fair market values of commodity derivative positions and exclude the impact of settlements on commodity derivatives during the period. We believe that non-cash fair value adjustments on commodity derivatives is a useful supplemental disclosure to differentiate non-cash fair market value adjustments from settlements on commodity derivatives during the period. Non-cash fair value adjustments on commodity derivatives is not a measure of financial or operating performance under U.S. GAAP, nor should it be considered a substitute for derivative fair value income or loss as reported in our consolidated statements of operations. 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. We continue to optimize our transportation portfolio using these volumes. See also Brokered natural gas and marketing expense below for more information on our net brokered margin.

Operating Costs per Mcfe

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:

|  | Three Months Ended September 30, |  |  | Nine Months Ended September 30, |
|  | 2021 |  |  | 2020 |  |  | Change |  |  | % |  |  | 2021 |  |  | 2020 |  |  | Change |  |  | % |
Direct operating expense |  | $ | 0.10 |  |  | $ | 0.10 |  |  | $ | — |  |  | $ | — |  |  | $ | 0.10 |  |  | $ | 0.12 |  |  | $ | (0.02 | ) |  |  | (17 | )%
Production and ad valorem tax expense |  |  | 0.04 |  |  |  | 0.03 |  |  |  | 0.01 |  |  |  | 33 | % |  |  | 0.04 |  |  |  | 0.03 |  |  |  | 0.01 |  |  |  | 33 | %
General and administrative expense |  |  | 0.25 |  |  |  | 0.19 |  |  |  | 0.06 |  |  |  | 32 | % |  |  | 0.22 |  |  |  | 0.19 |  |  |  | 0.03 |  |  |  | 16 | %
Interest expense |  |  | 0.29 |  |  |  | 0.24 |  |  |  | 0.05 |  |  |  | 21 | % |  |  | 0.30 |  |  |  | 0.23 |  |  |  | 0.07 |  |  |  | 30 | %
Depletion, depreciation and amortization expense |  |  | 0.47 |  |  |  | 0.48 |  |  |  | (0.01 | ) |  |  | (2 | )% |  |  | 0.47 |  |  |  | 0.49 |  |  |  | (0.02 | ) |  |  | (4 | )%

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

|  | Three Months Ended September 30, |  |  | Nine Months Ended September 30, |
|  | 2021 |  |  | 2020 |  |  | Change |  |  | % |  |  | 2021 |  |  | 2020 |  |  | Change |  |  | % |
Direct operating |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Lease operating expense |  | $ | 0.10 |  |  | $ | 0.10 |  |  | $ | — |  |  |  | — | % |  | $ | 0.09 |  |  | $ | 0.11 |  |  | $ | (0.02 | ) |  |  | (18 | )%
Workovers |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — | % |  |  | 0.01 |  |  |  | 0.01 |  |  |  | — |  |  |  | — | %
Stock-based compensation |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — | % |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — | %
Total direct operating expense |  | $ | 0.10 |  |  | $ | 0.10 |  |  | $ | — |  |  |  | — | % |  | $ | 0.10 |  |  | $ | 0.12 |  |  | $ | (0.02 | ) |  |  | (17 | )%

Production and ad valorem taxes are paid based on market prices rather than hedged prices. This expense category is predominately comprised of the Pennsylvania impact fee. In February 2012, the Commonwealth of Pennsylvania enacted an “impact fee” 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:

|  | Three Months Ended September 30, |  |  | Nine Months Ended September 30, |
|  | 2021 |  |  | 2020 |  |  | Change |  |  | % |  |  | 2021 |  |  | 2020 |  |  | Change |  |  | % |
Production and ad valorem taxes |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Impact fee |  | $ | 0.04 |  |  | $ | 0.02 |  |  | $ | 0.02 |  |  |  | 100 | % |  | $ | 0.04 |  |  | $ | 0.02 |  |  | $ | 0.02 |  |  |  | 100 | %
Production and ad valorem taxes |  |  | — |  |  |  | 0.01 |  |  |  | (0.01 | ) |  |  | (100 | )% |  |  | — |  |  |  | 0.01 |  |  |  | (0.01 | ) |  |  | (100 | )%
Total production and ad valorem taxes |  | $ | 0.04 |  |  | $ | 0.03 |  |  | $ | 0.01 |  |  |  | 33 | % |  | $ | 0.04 |  |  | $ | 0.03 |  |  | $ | 0.01 |  |  |  | 33 | %

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

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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:

|  | Three Months Ended September 30, |  |  | Nine Months Ended September 30, |
|  | 2021 |  |  | 2020 |  |  | Change |  |  | % |  |  | 2021 |  |  | 2020 |  |  | Change |  |  | % |
General and administrative |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
General and administrative |  | $ | 0.20 |  |  | $ | 0.15 |  |  | $ | 0.05 |  |  |  | 33 | % |  | $ | 0.17 |  |  | $ | 0.15 |  |  | $ | 0.02 |  |  |  | 13 | %
Stock-based compensation |  |  | 0.05 |  |  |  | 0.04 |  |  |  | 0.01 |  |  |  | 25 | % |  |  | 0.05 |  |  |  | 0.04 |  |  |  | 0.01 |  |  |  | 25 | %
Total general and administrative expense |  | $ | 0.25 |  |  | $ | 0.19 |  |  | $ | 0.06 |  |  |  | 32 | % |  | $ | 0.22 |  |  | $ | 0.19 |  |  | $ | 0.03 |  |  |  | 16 | %

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:

| Three Months Ended September 30, |  |  | Nine Months Ended September 30, |
| 2021 |  |  | 2020 |  |  | Change |  |  | % |  |  | 2021 |  |  | 2020 |  |  | Change |  |  | % |
Bank credit facility | $ | 0.02 |  |  | $ | 0.04 |  |  | $ | (0.02 | ) |  |  | (50 | )% |  | $ | 0.02 |  |  | $ | 0.03 |  |  | $ | (0.01 | ) |  |  | (33 | )%
Senior notes |  | 0.26 |  |  |  | 0.19 |  |  |  | 0.07 |  |  |  | 37 | % |  |  | 0.27 |  |  |  | 0.19 |  |  |  | 0.08 |  |  |  | 42 | %
Amortization of deferred financing costs and other |  | 0.01 |  |  |  | 0.01 |  |  |  | — |  |  |  | — | % |  |  | 0.01 |  |  |  | 0.01 |  |  |  | — |  |  |  | — | %
Total interest expense | $ | 0.29 |  |  | $ | 0.24 |  |  | $ | 0.05 |  |  |  | 21 | % |  | $ | 0.30 |  |  | $ | 0.23 |  |  | $ | 0.07 |  |  |  | 30 | %
Average debt outstanding ($000’s) | $ | 3,089,472 |  |  | $ | 3,237,459 |  |  | $ | (147,987 | ) |  |  | (5 | )% |  | $ | 3,141,729 |  |  | $ | 3,268,227 |  |  | $ | (126,498 | ) |  |  | (4 | )%
Average interest rate (a) |  | 7.1 | % |  |  | 5.7 | % |  |  | 1.4 | % |  |  | 25 | % |  |  | 7.0 | % |  |  | 5.6 | % |  |  | 1.4 | % |  |  | 25 | %

(a) | 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. This decrease is due to a 2% decrease in depletion rates and a 3% 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. 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:

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|  | Three Months Ended September 30, |  |  | Nine Months Ended September 30, |
|  | 2021 |  |  | 2020 |  |  | Change |  |  | % |  |  | 2021 |  |  | 2020 |  |  | Change |  |  | % |
DD&A |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Depletion and amortization |  | $ | 0.46 |  |  | $ | 0.47 |  |  | $ | (0.01 | ) |  |  | (2 | )% |  | $ | 0.46 |  |  | $ | 0.48 |  |  | $ | (0.02 | ) |  |  | (4 | )%
Depreciation |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — | % |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — | %
Accretion and other |  |  | 0.01 |  |  |  | 0.01 |  |  |  | — |  |  |  | — | % |  |  | 0.01 |  |  |  | 0.01 |  |  |  | — |  |  |  | — | %
Total DD&A expense |  | $ | 0.47 |  |  | $ | 0.48 |  |  | $ | (0.01 | ) |  |  | (2 | )% |  | $ | 0.47 |  |  | $ | 0.49 |  |  | $ | (0.02 | ) |  |  | (4 | )%

Other Operating Expenses

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):

|  | Three Months Ended September 30, |  |  | Nine Months Ended September 30, |
|  | 2021 |  |  | 2020 |  |  | 2021 |  |  | 2020 |
Direct operating expense |  | $ | 319 |  |  | $ | (74 | ) |  | $ | 986 |  |  | $ | 810 |
Brokered natural gas and marketing expense |  |  | 446 |  |  |  | 324 |  |  |  | 1,339 |  |  |  | 905 |
Exploration expense |  |  | 368 |  |  |  | 189 |  |  |  | 1,116 |  |  |  | 891 |
General and administrative expense |  |  | 9,845 |  |  |  | 6,863 |  |  |  | 28,632 |  |  |  | 24,071 |
Termination costs |  |  | — |  |  |  | 2,020 |  |  |  | — |  |  |  | 2,020 |
Total stock-based compensation |  | $ | 10,978 |  |  | $ | 9,322 |  |  | $ | 32,073 |  |  | $ | 28,697 |

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):

| Three Months Ended September 30, |  |  | Nine Months Ended September 30, |
| 2021 |  |  | 2020 |  |  | Change |  |  | % |  |  | 2021 |  |  | 2020 |  |  | Change |  |  | % |
Brokered natural gas and marketing |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Brokered natural gas sales | $ | 101,095 |  |  | $ | 39,180 |  |  | $ | 61,915 |  |  |  | 158 | % |  | $ | 231,335 |  |  | $ | 94,364 |  |  | $ | 136,971 |  |  |  | 145 | %
Brokered NGLs sales |  | 2,764 |  |  |  | 1,084 |  |  |  | 1,680 |  |  |  | 155 | % |  |  | 3,912 |  |  |  | 3,230 |  |  |  | 682 |  |  |  | 21 | %
Other marketing revenue |  | 1,695 |  |  |  | 2,218 |  |  |  | (523 | ) |  |  | (24 | )% |  |  | 13,421 |  |  |  | 7,128 |  |  |  | 6,293 |  |  |  | 88 | %
Brokered natural gas purchases (1) |  | (100,868 | ) |  |  | (44,690 | ) |  |  | (56,178 | ) |  |  | (126 | )% |  |  | (236,498 | ) |  |  | (108,061 | ) |  |  | (128,437 | ) |  |  | (119 | )%
Brokered NGLs purchases |  | (2,867 | ) |  |  | (1,219 | ) |  |  | (1,648 | ) |  |  | (135 | )% |  |  | (3,924 | ) |  |  | (4,030 | ) |  |  | 106 |  |  |  | 3 | %
Other marketing expense |  | (2,103 | ) |  |  | (2,058 | ) |  |  | (45 | ) |  |  | (2 | )% |  |  | (6,755 | ) |  |  | (6,661 | ) |  |  | (94 | ) |  |  | (1 | )%
Net brokered natural gas and marketing margin | $ | (284 | ) |  | $ | (5,485 | ) |  | $ | 5,201 |  |  |  | 95 | % |  | $ | 1,491 |  |  | $ | (14,030 | ) |  | $ | 15,521 |  |  |  | 111 | %

(1) | Includes transportation costs.

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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):

|  | Three Months Ended September 30, |  |  | Nine Months Ended September 30, |
|  | 2021 |  |  | 2020 |  |  | Change |  |  | % |  |  | 2021 |  |  | 2020 |  |  | Change |  |  | % |
Exploration |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Delay rentals and other |  | $ | 4,370 |  |  | $ | 6,737 |  |  | $ | (2,367 | ) |  |  | (35 | )% |  | $ | 11,871 |  |  | $ | 17,711 |  |  | $ | (5,840 | ) |  |  | (33 | )%
Personnel expense |  |  | 1,131 |  |  |  | 1,152 |  |  |  | (21 | ) |  |  | (2 | )% |  |  | 3,530 |  |  |  | 4,580 |  |  |  | (1,050 | ) |  |  | (23 | )%
Stock-based compensation expense |  |  | 368 |  |  |  | 189 |  |  |  | 179 |  |  |  | 95 | % |  |  | 1,117 |  |  |  | 891 |  |  |  | 226 |  |  |  | 25 | %
Seismic |  |  | 12 |  |  |  | 8 |  |  |  | 4 |  |  |  | 50 | % |  |  | (71 | ) |  |  | 8 |  |  |  | (79 | ) |  | NM |
Total exploration expense |  | $ | 5,881 |  |  | $ | 8,086 |  |  | $ | (2,205 | ) |  |  | (27 | )% |  | $ | 16,447 |  |  | $ | 23,190 |  |  | $ | (6,743 | ) |  |  | (29 | )%

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. 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.

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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. The 2021 and 2020 effective tax rates were different than the statutory tax rate due to state income taxes, equity compensation, valuation allowances and other discrete tax items.

Management’s Discussion and Analysis of Financial Condition, Capital Resources and Liquidity

Cash Flow

Cash flows from operations are primarily affected by production volumes and commodity prices, net of the effects of settlements of our derivatives. 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. 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. 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, |
|  | 2021 |  |  | 2020 |
Sources of cash and cash equivalents |  |  |  |  |  |
Operating activities |  | $ | 475,289 |  |  | $ | 178,974 |
Disposal of assets |  |  | 237 |  |  |  | 246,083 |
Issuance of senior notes |  |  | 600,000 |  |  |  | 850,000 |
Borrowing on credit facility |  |  | 1,250,000 |  |  |  | 1,676,000 |
Other |  |  | 35,011 |  |  |  | 21,664 |
Total sources of cash and cash equivalents |  | $ | 2,360,537 |  |  | $ | 2,972,721 |
Uses of cash and cash equivalents |  |  |  |  |  |
Additions to natural gas and oil properties |  | $ | (311,709 | ) |  | $ | (321,849 | )
Repayment on credit facility |  |  | (1,922,000 | ) |  |  | (1,447,000 | )
Acreage purchases |  |  | (20,302 | ) |  |  | (18,554 | )
Additions to field service assets |  |  | (720 | ) |  |  | (2,493 | )
Repayment of senior and senior subordinated notes |  |  | (63,324 | ) |  |  | (1,120,634 | )
Treasury stock purchases |  |  | — |  |  |  | (22,992 | )
Debt issuance costs |  |  | (8,799 | ) |  |  | (12,735 | )
Other |  |  | (33,663 | ) |  |  | (26,493 | )
Total uses of cash and cash equivalents |  | $ | (2,360,517 | ) |  | $ | (2,972,750 | )

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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 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. Net cash provided from operating activities was affected by a 8% 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.

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. 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:

39


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; and

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.

Shelf Registration

We have a universal shelf registration statement filed with the SEC under which we, as a "well-known seasoned issuer" for purposes of SEC rules, have the ability to sell an indeterminate amount of various types of debt and equity securities.

Cash Dividend Payments

In January 2020, we announced that the Board of Directors suspended the dividend on our common stock. 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.

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.

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.

Off-Balance Sheet Arrangements

We do not currently utilize any significant off-balance sheet arrangements with unconsolidated entities to enhance our liquidity or capital resource position, or for any other purpose. However, as is customary in the oil and gas industry, we have various contractual work commitments, some of which are described above under Cash Contractual Obligations.

Inflation and Changes in Prices

Our revenues, the value of our assets and our ability to obtain bank loans or additional capital on attractive terms have been and will continue to be affected by changes in natural gas, NGLs and oil prices and the costs to produce our reserves. 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.

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Forward-Looking Statements

Certain sections of Management’s Discussion and Analysis of Financial Condition and Results of Operations include forward-looking statements concerning trends or events potentially affecting our business. These statements contain words such as “anticipates,” “believes,” “expects,” “targets,” “plans,” “projects,” “could,” “may,” “should,” “would” or similar words indicating that future outcomes are uncertain. In accordance with “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, these statements are accompanied by cautionary language identifying important factors, though not necessarily all such factors, which could cause future outcomes to differ materially from those set forth in the forward-looking statements. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our current forecasts for our existing operations and do not include the potential impact of any future events. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise. For additional risk factors affecting our business, see Item 1A. Risk Factors as set forth in our Annual Report on Form 10-K for the year ended December 31, 2020, as filed with the SEC on February 23, 2021.

ITEM 3. QUANTITATIVE AND QUALITAT I VE DISCLOSURES ABOUT MARKET RISK

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in natural gas, NGLs and oil prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market-risk exposure. All of our market-risk sensitive instruments were entered into for purposes other than trading. All accounts are U.S. dollar denominated.

Market Risk

We are exposed to market risks related to the volatility of natural gas, NGLs and oil prices. We employ various strategies, including the use of commodity derivative instruments, to manage the risks related to these price fluctuations. 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. 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.

Natural gas and oil prices have been volatile and unpredictable for many years. Changes in natural gas prices affect us more than changes in oil prices because approximately 65% of our December 31, 2020 proved reserves are natural gas and 2% of proved reserves are oil and condensate. In addition, a portion of our NGLs, which are 33% of proved reserves, are also impacted by changes in oil prices. 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.

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Commodity Price Risk

We use commodity-based derivative contracts to manage exposures to commodity price fluctuations. We do not enter into these arrangements for speculative or trading purposes. At times, certain of our derivatives are swaps where we receive a fixed price for our production and pay market prices to the counterparty. Our derivatives program can also include collars, which establish a minimum floor price and a predetermined ceiling price. We have also entered into natural gas derivative instruments containing a fixed price swap and a sold option (which we refer to as a swaption). 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

$776.1 million. These contracts expire monthly through December 2023. At September 30, 2021, the following commodity derivative contracts were outstanding, excluding our basis swaps which are discussed below:

Period |  | Contract Type |  | Volume Hedged |  | Weighted Average Hedge Price |  |  | Fair Market Value |
|  |  |  |  |  | Swap |  |  | Sold Put |  |  | Floor |  |  | Ceiling |  |  |  |
|  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (in thousands) |
Natural Gas (1) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
2021 |  | Swaps |  | 583,152 Mmbtu/day |  | $ | 2.84 |  |  |  |  |  |  |  |  |  |  |  | $ | (164,114 | )
2021 |  | Collars |  | 227,391 Mmbtu/day |  |  |  |  |  |  |  | $ | 2.87 |  |  | $ | 3.42 |  |  | $ | (51,964 | )
2021 |  | Three-way Collars |  | 339,457 Mmbtu/day |  |  |  |  | $ | 2.26 |  |  | $ | 2.62 |  |  | $ | 3.04 |  |  | $ | (90,094 | )
2022 |  | Swaps |  | 382,329 Mmbtu/day |  | $ | 3.11 |  |  |  |  |  |  |  |  |  |  |  | $ | (185,289 | )
2022 |  | Collars |  | 213,438 Mmbtu/day |  |  |  |  |  |  |  | $ | 3.26 |  |  | $ | 3.70 |  |  | $ | (41,261 | )
2022 |  | Three-way Collars |  | 251,781 Mmbtu/day |  |  |  |  | $ | 2.37 |  |  | $ | 3.03 |  |  | $ | 3.77 |  |  | $ | (110,383 | )
January - March 2022 |  | Calls |  | 80,000 Mmbtu/day |  |  |  |  |  |  |  |  |  |  | $ | 6.02 |  |  | $ | (10,018 | )
2023 |  | Swaps |  | 60,000 Mmbtu/day |  | $ | 3.27 |  |  |  |  |  |  |  |  |  |  |  | $ | (4,266 | )
Crude Oil |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
2021 |  | Swaps |  | 7,500 bbls/day |  | $ | 56.92 |  |  |  |  |  |  |  |  |  |  |  | $ | (12,063 | )
2022 |  | Swaps |  | 5,811 bbls/day |  | $ | 59.59 |  |  |  |  |  |  |  |  |  |  |  | $ | (22,047 | )
2023 |  | Swaps |  | 500 bbls/day |  | $ | 63.50 |  |  |  |  |  |  |  |  |  |  |  | $ | (154 | )
NGLs (C3-Propane) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
2021 |  | Swaps |  | 6,000 bbls/day |  | $1.17/gallon |  |  |  |  |  |  |  |  |  |  |  | $ | (6,140 | )
2021 |  | Collars |  | 4,000 bbls/day |  |  |  |  |  |  |  | $1.00/gallon |  |  | $1.20/gallon |  |  | $ | (3,787 | )
NGLs (NC4-Normal Butane) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
2021 |  | Swaps |  | 2,663 bbls/day |  | $1.17/gallon |  |  |  |  |  |  |  |  |  |  |  | $ | (3,991 | )
2021 |  | Collars |  | 2,000 bbls/day |  |  |  |  |  |  |  | $1.00/gallon |  |  | $1.20/gallon |  |  | $ | (2,797 | )
NGLs (C5-Natural Gasoline) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
2021 |  | Swaps |  | 2,000 bbls/day |  | $1.41/gallon |  |  |  |  |  |  |  |  |  |  |  | $ | (2,822 | )
2021 |  | Collars |  | 3,000 bbls/day |  |  |  |  |  |  |  | $1.35/gallon |  |  | $1.55/gallon |  |  | $ | (2,693 | )
January - March 2022 |  | Swaps |  | 2,656 bbls/day |  | $1.59/gallon |  |  |  |  |  |  |  |  |  |  |  | $ | (1,069 | )
January - March 2022 |  | Collars |  | 2,000 bbls/day |  |  |  |  |  |  |  | $1.45/gallon |  |  | $1.60/gallon |  |  | $ | (1,035 | )

(1) | 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 believe NGLs prices are somewhat seasonal, particularly for propane. Therefore, the relationship of NGLs prices to NYMEX WTI (or West Texas Intermediate) will vary due to product components, seasonality and geographic supply and demand. We sell NGLs in several regional and international markets. If we are not able to sell or store NGLs, we may be required to curtail production or shift our drilling activities to dry gas areas.

Currently, the Appalachian region has limited local demand and infrastructure to accommodate ethane. We have agreements where we have contracted to either sell or transport ethane from our Marcellus Shale area. We cannot ensure that these facilities will remain available. If we are not able to sell ethane under at least one of these agreements, we may be required to curtail production or, as we have done in the past, purchase or divert natural gas to blend with our rich residue gas.

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Other Commodity Risk

We are impacted by basis risk, caused by factors that affect the relationship between commodity futures prices reflected in derivative commodity instruments and the cash market price of the underlying commodity. Natural gas transaction prices are frequently based on industry reference prices that may vary from prices experienced in local markets. 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. 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. We remain at risk for possible changes in the market value of commodity derivative instruments; however, such risks should be mitigated by price changes in the underlying physical commodity (in thousands):

|  |  |  |  | Hypothetical Change in Fair Value |  |  | Hypothetical Change in Fair Value |
|  |  |  |  | Increase in Commodity Price of |  |  | Decrease in Commodity Price of |
|  | Fair Value |  |  | 10% |  |  | 25% |  |  | 10% |  |  | 25% |
Swaps |  | $ | (401,955 | ) |  | $ | (128,462 | ) |  | $ | (321,157 | ) |  | $ | 128,462 |  |  | $ | 321,157 |
Collars |  |  | (103,537 | ) |  |  | (45,869 | ) |  |  | (116,475 | ) |  |  | 44,762 |  |  |  | 108,887 |
Three-way collars |  |  | (200,477 | ) |  |  | (54,472 | ) |  |  | (139,150 | ) |  |  | 51,844 |  |  |  | 123,317 |
Calls |  |  | (10,018 | ) |  |  | (2,370 | ) |  |  | (6,374 | ) |  |  | 2,105 |  |  |  | 4,801 |
Swaptions |  |  | (60,132 | ) |  |  | (20,314 | ) |  |  | (52,142 | ) |  |  | 18,809 |  |  |  | 42,809 |
Basis swaps |  |  | 8,867 |  |  |  | 7,252 |  |  |  | 18,129 |  |  |  | (7,252 | ) |  |  | (18,129 | )
Freight swaps |  |  | (26 | ) |  |  | 296 |  |  |  | 741 |  |  |  | (296 | ) |  |  | (741 | )
Divestiture contingent consideration |  |  | 50,220 |  |  |  | 3,850 |  |  |  | 7,820 |  |  |  | (4,880 | ) |  |  | (13,670 | )

Our commodity-based derivative contracts expose us to the credit risk of non-performance by the counterparty to the contracts. Our exposure is diversified primarily among major investment grade financial institutions and we have master netting agreements with our counterparties that provide for offsetting payables against receivables from separate derivative contracts. 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. Counterparty credit risk is considered when determining the fair value of our derivative contracts. While our counterparties are primarily major investment grade financial institutions, the fair value of our derivative contracts has been adjusted to account for the risk of non-performance by certain of our counterparties, which was immaterial. Through March 31, 2021, our propane and butane sales from the Marcus Hook facility near Philadelphia were short-term and to a single purchaser and our ethane sales were to a single international customer. As of April 1, 2021, other than limited spot sales, our propane and butane sales have been diversified among several purchasers and are for set terms of twelve to twenty-four months.

Interest Rate Risk

We are exposed to interest rate risk on our bank debt. 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.

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IT EM 4. CONTROLS A ND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report on Form 10-Q. 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.

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.

P ART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

See Note 17 to our unaudited consolidated financial statements entitled “Commitments and Contingencies” included in Part I Item 1 above for a summary of our legal proceedings, such information being incorporated herein by reference.

Environmental Proceedings

Our subsidiary, Range Resources – Appalachia, LLC, was notified by the DEP that it intends to assess a civil penalty under the Clean Streams Law and the 2012 Oil and Gas Act in connection with one well in Lycoming County and ordered us to conduct certain remedial work and monitoring to prevent methane and other substances from allegedly escaping the gas well into the surrounding environment including into soil, groundwater, streams and other surrounding water sources. DEP initially issued an order specifying its demands to the subsidiary on May 11, 2015. We appealed the order and the appeal was subsequently settled and discontinued whereupon we agreed to conduct certain, limited remedial work at the one well and continue monitoring water sources in the area and DEP did not assess any fines at that time. Thereafter, on January 13, 2020, DEP issued a new order regarding the same one well in Lycoming County which set forth similar allegations and demands as set forth above. This new order was issued despite considerable data and evidence presented to DEP over the course of the investigation that this one well has not been nor is currently the source of methane in the environment nor any water supplies, but rather the methane existed in the environment before the commencement of our operations. We appealed the January 2020 order and intend to vigorously defend against the allegations asserted by DEP; however, a resolution of this matter may nonetheless result in monetary sanctions of more than $250,000.

From time to time, we receive notices of violation from governmental and regulatory authorities in areas in which we operate relating to alleged violations of environmental statutes or the rules and regulations promulgated thereunder. While we cannot predict with certainty whether these notices of violation will result in fines and/or penalties, if fines and/or penalties are imposed, they may result in monetary sanctions, individually or in the aggregate, in excess of $250,000.

IT EM 1A. RISK FACTORS

We are subject to various risks and uncertainties in the course of our business. In addition to the factors discussed elsewhere in this report, you should carefully consider the risks and uncertainties described under Item 1A. Risk Factors filed in our Annual Report on Form 10-K for the year ended December 31, 2020.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

During third quarter 2021, we did not purchase any shares. Through September 30, 2021, we have repurchased 10.0 million shares of common stock at a cost of approximately $29.9 million, excluding fees and commissions, as part of a $100.0 million share repurchase program announced in October 2019. Shares repurchased as of September 30, 2021 are held as treasury stock.

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IT EM 6. EXHIBITS

Exhibit index

Exhibit Number |  |  | Exhibit Description
| 3.1 |  |  | Restated Certificate of Incorporation of Range Resources Corporation (incorporated by reference to Exhibit 3.1.1 to our Form 10-Q (File No. 001-12209) as filed with the SEC on May 5, 2004, as amended by the Certificate of First Amendment to Restated Certificate of Incorporation of Range Resources Corporation (incorporated by reference to Exhibit 3.1 to our Form 10-Q (File No. 001-12209) as filed with the SEC on July 28, 2005) and the Certificate of Second Amendment to Restated Certificate of Incorporation of Range Resources Corporation (incorporated by reference to Exhibit 3.1 to our Form 10-Q (File No. 001-12209) as filed with the SEC on July 24, 2008)
| 3.2 |  |  | Amended and Restated By-laws of Range Resources Corporation (incorporated by reference to Exhibit 3.1 to our Form 8-K (File No. 001-12209) as filed with the SEC on May 19, 2016)
| 31.1* |  |  | Certification by the President and Chief Executive Officer of Range Resources Corporation Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
| 31.2* |  |  | Certification by the Chief Financial Officer of Range Resources Corporation Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
| 32.1** |  |  | Certification by the President and Chief Executive Officer of Range Resources Corporation Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
| 32.2** |  |  | Certification by the Chief Financial Officer of Range Resources Corporation Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
| 101. INS* |  |  | Inline XBRL Instance Document – the XBRL Instance Document does not appear in the Interactive Data file because its XBRL tags are embedded within the Inline XBRL document
| 101. SCH* |  |  | Inline XBRL Taxonomy Extension Schema
| 101. CAL* |  |  | Inline XBRL Taxonomy Extension Calculation Linkbase Document
| 101. DEF* |  |  | Inline XBRL Taxonomy Extension Definition Linkbase Document
| 101. LAB* |  |  | Inline XBRL Taxonomy Extension Label Linkbase Document
| 101. PRE* |  |  | Inline XBRL Taxonomy Extension Presentation Linkbase Document
| 104 * |  |  | Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101)

* filed herewith

** furnished herewith

45

SI GNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

Date: October 26 , 2021

RANGE RESOURCES CORPORATION
By: |  | /s/ MARK S. SCUCCHI
|  | Mark S. Scucchi
|  | Senior Vice President and Chief Financial Officer

Date: October 26, 2021

RANGE RESOURCES CORPORATION
By: |  | /s/ DORI A. GINN
|  | Dori A. Ginn
|  | Senior Vice President – Controller and Principal Accounting Officer

46