EX-99.4 6 tm229424d1_ex99-4.htm EXHIBIT 99.4

Exhibit 99.4

EXTRACTION OIL & GAS, INC.

Consolidated Financial Statements and Notes

For the Years Ended December 31, 2020 and 2019

Report of Independent Registered Public Accounting Firm

To the Board of Directors of Civitas Resources, Inc. and Stockholder of Extraction Oil & Gas, Inc.

Opinion on the Financial Statements

We have audited the consolidated statements of operations, of changes in stockholders’ equity (deficit) and noncontrolling interest and of cash flows of Extraction Oil & Gas, Inc. and its subsidiaries (the “Company”) for the years ended December 31, 2020 and 2019, including the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the results of operations and cash flows of the Company for the years ended December 31, 2020 and 2019 in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Denver, Colorado

March 18, 2021

We served as the Company's auditor from 2014 to 2021.

EXTRACTION OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Debtor-In-Possession)

(In thousands, except per share data)

|  | For the Year Ended December 31, |
|  | 2020 |  |  | 2019 |
Revenues: |  |  |  |  |  |  |  |
Oil sales |  | $ | 382,526 |  |  | $ | 721,429 |
Natural gas sales |  |  | 96,701 |  |  |  | 108,873 |
NGL sales |  |  | 77,204 |  |  |  | 75,072 |
Gathering and compression |  |  | 1,473 |  |  |  | 1,261 |
Total Revenues |  |  | 557,904 |  |  |  | 906,635 |
Operating Expenses: |  |  |  |  |  |  |  |
Lease operating expenses |  |  | 77,836 |  |  |  | 97,254 |
Midstream operating expenses |  |  | 3,935 |  |  |  | 2,258 |
Transportation and gathering |  |  | 138,552 |  |  |  | 53,140 |
Production taxes |  |  | 29,038 |  |  |  | 68,182 |
Exploration and abandonment expenses |  |  | 258,932 |  |  |  | 88,794 |
Depletion, depreciation, amortization and accretion |  |  | 332,319 |  |  |  | 524,537 |
Impairment of long lived assets and goodwill |  |  | 208,463 |  |  |  | 1,337,996 |
(Gain) loss on sale of property and equipment and assets of unconsolidated subsidiary |  |  | (122 | ) |  |  | 421 |
General and administrative expenses |  |  | 55,182 |  |  |  | 98,845 |
Other operating expenses |  |  | 79,615 |  |  |  | — |
Total Operating Expenses |  |  | 1,183,750 |  |  |  | 2,271,427 |
Operating Income (Loss) |  |  | (625,846 | ) |  |  | (1,364,792 | )
Other Income (Expense): |  |  |  |  |  |  |  |
Commodity derivatives gain (loss) |  |  | 164,968 |  |  |  | (37,107 | )
Loss on deconsolidation of Elevation Midstream, LLC |  |  | (73,139 | ) |  |  | — |
Reorganization items, net |  |  | (676,855 | ) |  |  | — |
Interest expense (1) |  |  | (57,143 | ) |  |  | (79,232 | )
Other income |  |  | 481 |  |  |  | 4,535 |
Total Other Expense |  |  | (641,688 | ) |  |  | (111,804 | )
Income (Loss) Before Income Taxes |  |  | (1,267,534 | ) |  |  | (1,476,596 | )
Income tax (expense) benefit |  |  | — |  |  |  | 109,176 |
Net Income (Loss) |  | $ | (1,267,534 | ) |  | $ | (1,367,420 | )
Net income attributable to noncontrolling interest |  |  | 6,160 |  |  |  | 19,992 |
Net Income (Loss) Attributable to Extraction Oil & Gas, Inc. |  |  | (1,273,694 | ) |  |  | (1,387,412 | )
Adjustments to reflect Series A Preferred Stock dividends and accretion of discount |  |  | (16,115 | ) |  |  | (19,436 | )
Net Income (Loss) Available to Common Shareholders, Basic and Diluted |  | $ | (1,289,809 | ) |  | $ | (1,406,848 | )
Net Income (Loss) Per Common Share—Note 15 |  |  |  |  |  |  |  |
Basic and diluted |  | $ | (9.34 | ) |  | $ | (9.29 | )
Weighted Average Common Shares Outstanding |  |  |  |  |  |  |  |
Basic and diluted |  |  | 138,149 |  |  |  | 151,481 |

(1) Absent the automatic stay described in Note 7—Long-Term Debt, interest expense for the year ended December 31, 2020 would have been $94.5 million.

THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF

THESE CONSOLIDATED FINANCIAL STATEMENTS

EXTRACTION OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Debtor-In-Possession)

(In thousands)

|  | For the Year Ended December 31, |
|  | 2020 |  |  | 2019 |
Cash flows from operating activities: |  |  |  |  |  |  |  |
Net income (loss) |  | $ | (1,267,534 | ) |  | $ | (1,367,420 | )
Reconciliation of net income (loss) to net cash provided by operating activities: |  |  |  |  |  |  |  |
Depletion, depreciation, amortization and accretion |  |  | 332,319 |  |  |  | 524,537 |
Abandonment of unproved properties |  |  | 253,142 |  |  |  | 73,729 |
Impairment of long lived assets and goodwill |  |  | 208,463 |  |  |  | 1,337,996 |
(Gain) loss on sale of property and equipment |  |  | (122 | ) |  |  | 1,431 |
Gain on sale of assets of unconsolidated subsidiary |  |  | — |  |  |  | (1,010 | )
Gain on repurchase of 2026 Senior Notes |  |  | — |  |  |  | (10,486 | )
Amortization of debt issuance costs and debt discount |  |  | 3,685 |  |  |  | 5,482 |
Non-cash lease expenses |  |  | 11,724 |  |  |  | 11,146 |
Non-cash reorganization items, net |  |  | 10,636 |  |  |  | — |
Contract asset |  |  | 12,317 |  |  |  | 24,700 |
(Gain) loss on commodity derivatives |  |  | (164,968 | ) |  |  | 37,107 |
Settlements on commodity derivatives |  |  | 89,800 |  |  |  | (678 | )
Premiums paid on commodity derivatives |  |  | — |  |  |  | (2,852 | )
Loss on deconsolidation of Elevation Midstream, LLC |  |  | 73,139 |  |  |  | — |
Earnings in unconsolidated subsidiaries |  |  | (480 | ) |  |  | (2,285 | )
Distributions from unconsolidated subsidiary |  |  | — |  |  |  | 3,200 |
Deferred income tax expense (benefit) |  |  | — |  |  |  | (109,176 | )
Stock-based compensation |  |  | 6,511 |  |  |  | 43,954 |
Changes in current assets and liabilities: |  |  |  |  |  |  |  |
Accounts receivable—trade |  |  | 16,900 |  |  |  | 3,630 |
Accounts receivable—oil, natural gas and NGL sales |  |  | 41,674 |  |  |  | (12,996 | )
Inventory, prepaid expenses and other |  |  | (17,555 | ) |  |  | (332 | )
Accounts payable and accrued liabilities |  |  | 87,228 |  |  |  | (5,753 | )
Accrued damages for rejected and settled contracts |  |  | 582,439 |  |  |  | — |
Revenue payable |  |  | (147 | ) |  |  | (7,598 | )
Production taxes payable |  |  | (3,631 | ) |  |  | 40,957 |
Accrued interest payable |  |  | 11,743 |  |  |  | (1,624 | )
Asset retirement expenditures |  |  | (21,308 | ) |  |  | (27,702 | )
Net cash provided by operating activities |  |  | 265,975 |  |  |  | 557,957 |
Cash flows from investing activities: |  |  |  |  |  |  |  |
Oil and gas property additions |  |  | (249,984 | ) |  |  | (635,853 | )
Sale of property and equipment |  |  | 14,420 |  |  |  | 56,305 |
Gathering systems and facilities additions, net of cost reimbursements |  |  | 4,193 |  |  |  | (202,513 | )
Other property and equipment additions |  |  | (3,697 | ) |  |  | (39,090 | )
Investment in unconsolidated subsidiaries |  |  | (10,033 | ) |  |  | (30,012 | )
Sale of assets of unconsolidated subsidiary |  |  | — |  |  |  | 1,010 |
Net cash used in investing activities |  |  | (245,101 | ) |  |  | (850,153 | )
Cash flows from financing activities: |  |  |  |  |  |  |  |
Borrowings under Prior Credit Facility |  |  | 200,500 |  |  |  | 465,000 |
Repayments under Prior Credit Facility |  |  | (70,000 | ) |  |  | (280,000 | )
Borrowings under DIP Credit Facility |  |  | 35,000 |  |  |  | — |
Repayments under DIP Credit Facility |  |  | (3,273 | ) |  |  | — |
Repurchase of 2026 Senior Notes |  |  | — |  |  |  | (39,325 | )
Repurchase of common stock |  |  | — |  |  |  | (137,743 | )
Payment of employee payroll withholding taxes |  |  | (120 | ) |  |  | (1,851 | )
Debt issuance costs and other financing fees |  |  | (1,745 | ) |  |  | (2,104 | )
Dividends on Series A Preferred Stock |  |  | — |  |  |  | (10,885 | )
Proceeds from issuance of Preferred Units |  |  | — |  |  |  | 99,000 |
Preferred Unit issuance costs |  |  | — |  |  |  | (2,500 | )
Net cash provided by financing activities |  |  | 160,362 |  |  |  | 89,592 |
Effect of deconsolidation of Elevation Midstream, LLC |  |  | (7,728 | ) |  |  | — |
Increase (decrease) in cash, cash equivalents and restricted cash |  |  | 173,508 |  |  |  | (202,604 | )
Cash, cash equivalents and restricted cash at beginning of period |  |  | 32,382 |  |  |  | 234,986 |
Cash, cash equivalents and restricted cash at end of the period |  | $ | 205,890 |  |  | $ | 32,382 |
Supplemental cash flow information: |  |  |  |  |  |  |  |
Property and equipment included in accounts payable and accrued liabilities |  | $ | 14,878 |  |  | $ | 118,152 |
Cash paid for interest |  |  | 47,032 |  |  |  | 93,084 |
Cash paid for reorganization items |  |  | 34,356 |  |  |  | — |
Preferred Units commitment fees and dividends paid-in-kind |  |  | 6,160 |  |  |  | 19,992 |
Series A Preferred Stock dividends paid-in-kind |  |  | 8,749 |  |  |  | 4,632 |
Accretion of beneficial conversion feature of Series A Preferred Stock |  |  | 7,366 |  |  |  | 6,640 |
Derivative unwinds decreasing Prior Credit Facility |  |  | 96,065 |  |  |  | — |
Draw on letter of credit increasing Prior Credit Facility |  |  | 24,311 |  |  |  | — |

THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF

THESE CONSOLIDATED FINANCIAL STATEMENTS

EXTRACTION OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY (DEFICIT) AND NONCONTROLLING INTEREST

(Debtor-In-Possession)

(In thousands)

|  | Common Stock |  |  | Treasury Stock |  |  | Additional |  |  |  |  |  | Extraction Oil & Gas, Inc. |  |  | Noncontrolling Interest |  |  | Total |
|  | Shares |  |  | Amount |  |  | Shares |  |  | Amount |  |  | Paid in Capital |  |  | (Accumulated Deficit) |  |  | Stockholders’ Equity (Deficit) |  |  | Amount |  |  | Stockholders’ Equity (Deficit) |
Balance at January 1, 2019 |  |  | 176,210 |  |  | $ | 1,678 |  |  |  | 4,543 |  |  | $ | (32,737 | ) |  | $ | 2,153,661 |  |  | $ | (375,788 | ) |  | $ | 1,746,814 |  |  | $ | 147,872 |  |  | $ | 1,894,686 |
Preferred Units issued |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 99,000 |  |  |  | 99,000 |
Preferred Units issuance costs |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (2,500 | ) |  |  | (2,500 | )
Preferred Units commitment fees and dividends paid-in-kind |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (19,992 | ) |  |  | — |  |  |  | (19,992 | ) |  |  | 19,992 |  |  |  | — |
Stock-based compensation |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 44,001 |  |  |  | — |  |  |  | 44,001 |  |  |  | — |  |  |  | 44,001 |
Series A Preferred Stock dividends |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (12,796 | ) |  |  | — |  |  |  | (12,796 | ) |  |  | — |  |  |  | (12,796 | )
Accretion of beneficial conversion feature on Series A Preferred Stock |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (6,640 | ) |  |  | — |  |  |  | (6,640 | ) |  |  | — |  |  |  | (6,640 | )
Repurchase of common stock |  |  | — |  |  |  | (342 | ) |  |  | 34,316 |  |  |  | (137,401 | ) |  |  | — |  |  |  | — |  |  |  | (137,743 | ) |  |  | — |  |  |  | (137,743 | )
Restricted stock issued, net of tax withholdings and other |  |  | 307 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (1,851 | ) |  |  | — |  |  |  | (1,851 | ) |  |  | — |  |  |  | (1,851 | )
Net loss |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (1,367,420 | ) |  |  | (1,367,420 | ) |  |  | — |  |  |  | (1,367,420 | )
Balance at December 31, 2019 |  |  | 176,517 |  |  | $ | 1,336 |  |  |  | 38,859 |  |  | $ | (170,138 | ) |  | $ | 2,156,383 |  |  | $ | (1,743,208 | ) |  | $ | 244,373 |  |  | $ | 264,364 |  |  | $ | 508,737 |
Preferred Units commitment fees and dividends paid-in-kind |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (6,160 | ) |  |  | — |  |  |  | (6,160 | ) |  |  | 6,160 |  |  |  | — |
Stock-based compensation |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 6,511 |  |  |  | — |  |  |  | 6,511 |  |  |  | — |  |  |  | 6,511 |
Series A Preferred Stock dividends |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (8,749 | ) |  |  | — |  |  |  | (8,749 | ) |  |  | — |  |  |  | (8,749 | )
Accretion of beneficial conversion feature on Series A Preferred Stock |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (7,366 | ) |  |  | — |  |  |  | (7,366 | ) |  |  | — |  |  |  | (7,366 | )
Restricted stock issued, net of tax withholdings and other |  |  | 714 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (120 | ) |  |  | — |  |  |  | (120 | ) |  |  | — |  |  |  | (120 | )
Cancellation of Performance Stock Awards - Note 13 |  |  | (1,783 | ) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Net loss |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (1,267,534 | ) |  |  | (1,267,534 | ) |  |  | — |  |  |  | (1,267,534 | )
Effects of deconsolidation of Elevation Midstream, LLC |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (270,524 | ) |  |  | (270,524 | )
Balance at December 31, 2020 |  |  | 175,448 |  |  | $ | 1,336 |  |  |  | 38,859 |  |  | $ | (170,138 | ) |  | $ | 2,140,499 |  |  | $ | (3,010,742 | ) |  | $ | (1,039,045 | ) |  | $ | — |  |  | $ | (1,039,045 | )

THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF

THESE CONSOLIDATED FINANCIAL STATEMENTS

EXTRACTION OIL & GAS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1—Business and Organization

Extraction Oil & Gas, Inc. (the “Company” or “Extraction”) is an independent oil and gas company focused on the acquisition, development and production of oil, natural gas and natural gas liquids (“NGLs”) reserves in the Rocky Mountain region, primarily in the Wattenberg Field of the Denver-Julesburg Basin (the “DJ Basin”) of Colorado.

As described in the section below titled Voluntary Reorganization under Chapter 11 of the Bankruptcy Code, during the second quarter of 2020, the Company filed for bankruptcy and, as a result, was delisted from the NASDAQ Global Select Market on June 25, 2020 and began trading on the Pink Open Market under the symbol “XOGAQ.”

As described in the section below titled Emergence from Chapter 11 Bankruptcy, on January 20, 2021 the Company emerged from bankruptcy as a reorganized entity and, as a result, was relisted on the NASDAQ Global Select Market on January 21, 2021 and began trading under the symbol “XOG.”

To facilitate our financial statement presentations, the Company refers to the post-emergence reorganized company in these consolidated financial statements and footnotes as the Successor Company for periods subsequent to January 20, 2021 and to the pre-emergence company as the Predecessor Company for periods on or prior to January 20, 2021.

Voluntary Reorganization under Chapter 11 of the Bankruptcy Code

As previously disclosed, on June 14, 2020 (the “Petition Date”), Extraction and its wholly owned subsidiaries (collectively, the “Debtors”), filed voluntary petitions for relief under chapter 11 (“Chapter 11”) of title 11 of the United States Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”). The Debtors’ Chapter 11 cases (the “Chapter 11 Cases”) were jointly administered under the caption In re Extraction Oil & Gas., et al. Case No. 20-11548 (CSS).

While in Chapter 11, the Debtors continued to operate their businesses and manage their properties as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.

The commencement of a voluntary proceeding in bankruptcy constituted an immediate event of default under the Predecessor Credit Agreement (as defined in Note 7—Long-Term Debt) and the indentures governing the Company’s Senior Notes (as defined in Note 2—Basis of Presentation and Significant Accounting Policies), resulting in the automatic and immediate acceleration of all of the Company’s debt outstanding under the Predecessor Credit Agreement and Senior Notes. The Prior Credit Facility (as defined in Note 7—Long-Term Debt) was not classified as liabilities subject to compromise because it was fully secured and unimpaired before being paid off as part of the Company’s emergence from bankruptcy described below. Pursuant to the Bankruptcy Code and as described in Note 7—Long-Term Debt, the filing of the Chapter 11 Cases automatically stayed most actions against the Debtors, including most actions to collect indebtedness incurred prior to the Petition Date or to exercise control over the Debtors’ property.

Plan, Disclosure Statement, and Backstop Commitment Agreement

On July 30, 2020, the Debtors filed a proposed Plan of Reorganization (as amended, modified, or supplemented from time to time, the “Plan”) and related Disclosure Statement (as amended or modified, the “Disclosure Statement”) describing the Plan and the solicitation of votes to approve the same from certain of the Debtors’ creditors with respect to the Chapter 11 Cases. Subsequently on October 22, 2020 and November 5, 2020, the Debtors filed first and second amendments, respectively, to the Disclosure Statement. The hearing to consider approval of the Disclosure Statement was held on November 6, 2020. On November 6, 2020, the Bankruptcy Court approved the adequacy of the Disclosure Statement and the Debtors commenced a solicitation process to receive votes on the Plan. Pursuant to the terms of the Plan and as described in the Disclosure Statement, the Debtors also commenced a rights offering (the “Equity Rights Offering”), which was backstopped by certain holders of the Senior Notes. On November 6, 2020, the Bankruptcy Court approved the Backstop Commitment Agreement (the “Backstop Commitment Agreement”), which provided a commitment of $200 million. The hearing on the confirmation of the Plan was held on December 23, 2020, in which the Plan was approved.

Emergence from Chapter 11 Bankruptcy

On December 23, 2020, the Company filed the Sixth Amended Joint Plan of Reorganization of Extraction Oil & Gas, Inc. pursuant to Chapter 11 of the Bankruptcy Code. Also on December 23, 2020, the Bankruptcy Court entered an order (the “Confirmation Order”) confirming the Plan. The Plan is attached to the Confirmation Order as Exhibit A. The sixth-amended Plan and the Confirmation Order were previously filed as Exhibits 2.1 and 99.1 to the Company’s Current Report on Form 8-K filed with the U.S. Securities and Exchange Commission on December 30, 2020. On January 20, 2021 (the “Emergence Date”) the Plan became effective in accordance with its terms and the Company emerged from the Chapter 11 Cases. On the Emergence Date and pursuant to the Plan:

| • | The Company amended and restated its certificate of incorporation and bylaws;

| • | The Company constituted a new board of directors;

| • | The Company appointed a new Chief Executive Officer, President and Chief Operating Officer, and Chief Financial Officer;

| • | The Company issued new common stock in the Successor Company (the “New Common Stock”) and New Warrants (as defined in Note 11—Equity):

| ◦ | 2,832,833 shares of New Common Stock pro rata to holders of the 2024 Notes;

| ◦ | 4,854,017 shares of New Common Stock pro rata to holders of the 2026 Notes;

| ◦ | 179,472 shares of New Common Stock, 1,454,832 Tranche A Warrants to purchase 1,454,832 shares of New Common Stock and 727,420 Tranche B Warrants to purchase 727,420 shares of New Common Stock pro rata to holders of the Predecessor Company’s Series A Preferred Stock (the “Predecessor Preferred Stock”) outstanding prior to the Emergence Date;

| ◦ | 179,496 shares of New Common Stock, 1,454,854 Tranche A Warrants to purchase 1,454,854 shares of New Common Stock and 727,443 Tranche B Warrants to purchase 727,443 shares of New Common Stock pro rata to holders of the Predecessor Company’s existing common stock (the “Predecessor Common Stock”) outstanding prior to the Emergence Date;

| ◦ | 1,169,322 shares of New Common Stock to commitment parties under the Backstop Commitment Agreement in respect of the commitment premium due thereunder;

| ◦ | 844,760 shares of New Common Stock to the commitment parties under the Backstop Commitment Agreement in connection with their backstop obligation thereunder to purchase unsubscribed shares of New Common Stock;

| ◦ | 11,478,670 shares of New Common Stock were issued to participants in the Equity Rights Offering extended by the Company to the applicable classes under the Plan (including to the commitment parties party to the Backstop Commitment Agreement); and

| ◦ | 13,392 shares of New Common Stock were issued to participants in rights offering extended by the Company to certain holders of general unsecured claims.

| • | The Company entered into the RBL Credit Facility (as defined in Note 7—Long-Term Debt—RBL Credit Facility);

| • | The Company terminated the Prior Credit Facility (as defined in Note 7—Long-Term Debt—Prior Credit Facility), and the holders of claims under the Prior Credit Facility each received its ratable portion of the RBL Credit Facility for its allowed claims. All liens and security interests granted to secure such obligations were automatically terminated and are of no further force and effect;

| • | The Company terminated the DIP Credit Facility (as defined in Note 7—Long-Term Debt—DIP Credit Facility), and the holders of claims under the DIP Credit Facility received payment in full, in cash, for allowed claims. All liens and security interests granted to secure such obligations were automatically terminated and are of no further force and effect;

| • | The holders of certain trade claims, administrative claims, other secured claims and other priority claims that were allowed by the Bankruptcy Court received payment in full in cash upon emergence or through the ordinary course of business after the Emergence Date.

Tax Attributes and Net Operating Loss (“NOL”) Carryforwards

As of December 31, 2020, the Company had substantial tax NOL carryforwards and other tax attributes. Under the U.S. Internal Revenue Code of 1986, as amended (the “Code”), our ability to use these NOLs and other tax attributes may be limited if the Company experiences an “ownership change,” as determined under Section 382 of the Code. Accordingly, on July 13, 2020, the Company obtained a final order from the Bankruptcy Court that was intended to prevent an ownership change during the pendency of the Chapter 11 Cases and therefore protect the Company’s ability to use its tax attributes by imposing certain notice procedures and transfer restrictions on the trading of the Company’s Predecessor Common Stock and Predecessor Preferred Stock.

In general, the order applied to any person or entity that, directly or indirectly, beneficially owned (or would beneficially own as a result of a proposed transfer) at least 4.5% of the Company’s common stock or preferred stock. Such persons were required to notify the Company and the Bankruptcy Court before effecting a transaction involving the Company’s Predecessor Common Stock and Predecessor Preferred Stock, and the Company had the right to seek an injunction to prevent the transaction if it might have adversely affected the Company’s ability to use its tax attributes. The order also required any person or entity that, directly or indirectly, beneficially owned at least 50% of the Company’s Predecessor Common Stock and Predecessor Preferred Stock to notify the Company and the Bankruptcy Court prior to claiming any deduction for worthlessness of the Company’s Predecessor Common Stock and Predecessor Preferred Stock for a tax year ending before the Company’s emergence from chapter 11 protection and the Company had the right to seek an injunction to prevent the transaction if it might have adversely affected the Company’s ability to use its tax attributes.

Any purchase, sale or other transfer of, or any claim of a deduction for worthlessness with respect to, the Company’s Predecessor Common Stock and Predecessor Preferred Stock in violation of the restrictions of the order would have been null and void ab initio as an act in violation of a Bankruptcy Court order and would therefore have conferred no rights on a proposed transferee or such holder, as applicable.

However, the Company expects that it will be required to substantially reduce or eliminate certain of its tax attributes, including NOL carryforwards, as a result of cancellation of indebtedness income realized in connection with the Chapter 11 Cases. Additionally, the consummation of the Plan on the Emergence Date resulted in an “ownership change” under Section 382 of the Code. Absent an applicable exception, if a corporation undergoes an “ownership change,” the amount of its pre-ownership change NOLs that may be utilized to offset future taxable income generally will be subject to an annual limitation equal to the value of its stock immediately prior to the ownership change multiplied by the long-term tax-exempt rate, plus an additional amount calculated based on certain “built in gains” in its assets that may be deemed to be realized within a 5-year period following any ownership change. This limitation, in the case of the ownership change that occurred as a result of the consummation of the Plan, will be subject to additional rules under Sections 382(l)(5) or (l)(6) of the Code, depending upon whether we are eligible for the application of Section 382(l)(5) of the Code and, if so eligible, whether we affirmatively elect not to apply Section 382(l)(5) of the Code. As a result of such limitation, the Company’s ability to utilize any NOLs or other tax attributes that are not eliminated as a result of cancellation of indebtedness income arising from the consummation of the Plan may be materially limited in the future.

Fresh-Start Reporting

Upon the Emergence Date, we began our assessment of our qualifications for fresh-start reporting. In order to qualify for fresh-start reporting, under Accounting Standards Codification (“ASC”) Topic 852 — Reorganizations, (i) the holders of existing voting shares of the Company prior to its emergence must receive less than 50% of the voting shares of the Company outstanding following its emergence from bankruptcy and (ii) the reorganization value of our assets immediately prior to confirmation of the plan of reorganization must be less than the post-petition liabilities and allowed claims. If we qualify for fresh-start reporting, a new reporting entity will be considered to have been created, and, as a result, the Company will allocate the reorganization value of the Company to its individual assets, including property, plant and equipment, based on their estimated fair values. The process of estimating the fair value of the Company’s assets, liabilities and equity upon emergence is currently ongoing and, therefore, neither the amounts nor the qualification for this accounting treatment have been finalized. In support of the Plan, the enterprise value of the Successor Company was estimated and approved by the Bankruptcy Court to be in the range of $875 million to $1.275 billion. On the Emergence Date, pursuant to the terms of the Plan, the Successor Company entered into a $1.0 billion reserve-based credit agreement with an initial borrowing base of $500.0 million. Please see Note 7—Long-Term Debt for discussion of the Successor Company’s debt.

Deconsolidation of Elevation Midstream, LLC

Elevation Midstream, LLC (“Elevation”), a Delaware limited liability company, is focused on the construction and operation of gathering systems and facilities to serve the development of acreage in the Company’s Hawkeye and Southwest Wattenberg areas.

During the first quarter of 2020, Elevation’s then non-controlling interest owner, which owned 100% of Elevation’s preferred stock, per contractual agreement, expanded Elevation’s then five member board of managers by four seats and filled them with managers of their choosing (the “Board Expansion”). Because Extraction had the right to appoint only three of the managers of Elevation before and after Board Expansion, Extraction determined the Company had lost voting control of Elevation, and on March 16, 2020 deconsolidated Elevation and began accounting for the entity as an equity method investment. Though Extraction determined control of Elevation was lost under the voting interest model of consolidation, the Company also determined significant influence was not lost due to (1) Extraction owning 100% of the common stock, (2) Extraction appointing three of the nine managers of Elevation and (3) Extraction’s continuing involvement in the day-to-day operation of Elevation through a management services agreement. Because Extraction also determined the Company is not the primary beneficiary, Elevation Midstream, LLC is not a variable interest entity.

Extraction elected the fair value option to remeasure the Elevation equity method investment and determined it had no fair value. The Company recorded a $73.1 million loss on deconsolidation of the investment in the consolidated statements of operations for the three months ended March 31, 2020. Also during the three months ended March 31, 2020, Elevation determined certain gathering systems and facilities were impaired by $50.3 million as a result of the abandonment of certain projects. In accordance with ASC Topic 323-10-35-20: Investments—equity method and joint ventures, Extraction discontinued applying the equity method for Elevation as the impairment charge would have reduced the investment below zero.

On May 1, 2020, Elevation’s board of managers issued 1,530,000,000 common units at a price of $0.01 per unit to certain of Elevation’s members other than Extraction (the “Capital Raise”). The Capital Raise caused Extraction’s ownership of Elevation to be diluted to less than 0.01%. As a result of the Capital Raise, beginning in May 2020 Extraction began accounting for Elevation under the cost method of accounting. In December 2020, the Company reached a settlement with Elevation (as discussed in Note 15—Commitments and Contingencies — Elevation Gathering Agreements) which was approved by the Bankruptcy Court. As part of the settlement, the Company relinquished its remaining ownership in Elevation and has no more interest in Elevation as of December 31, 2020.

Note 2—Basis of Presentation and Significant Accounting Policies

Basis of Presentation

The consolidated financial statements include the accounts of the Company, including its subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation. The financial statements included herein were prepared from the records of the Company in accordance with accounting principles generally accepted in the United States of America (“GAAP”).

Use of Estimates in the Preparation of Financial Statements

The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant areas requiring the use of assumptions, judgments and estimates include (1) oil and gas reserves; (2) cash flow estimates used in impairment testing of oil and gas properties and goodwill; (3) depreciation, depletion, amortization and accretion; (4) asset retirement obligations; (5) assigning fair value and allocating purchase price in connection with business combinations, including the determination of any resulting goodwill; (6) accrued revenue and related receivables; (7) valuation of commodity derivative instruments; (8) accrued liabilities; (9) valuation of stock-based payments, and (10) income taxes. Although management believes these estimates are reasonable, actual results could differ from these estimates. The Company evaluates its estimates on an on-going basis and bases its estimates on historical experience and on various other assumptions the Company believes to be reasonable under the circumstances.

Significant Accounting Policies

Beginning after the Petition Date, the Company has applied ASC Topic 852 — Reorganizations in preparing the consolidated financial statements. ASC 852 requires the financial statements, for periods subsequent to the Chapter 11 Cases’ filing date, to distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain expenses incurred during the bankruptcy proceedings, including unamortized debt issuance costs associated with debt classified as liabilities subject to compromise, are recorded as reorganization items. These liabilities are reported at the amounts the Company anticipates will be allowed by the Bankruptcy Court, even if they may be settled for lesser amounts.

GAAP requires certain additional reporting for financial statements prepared between the Petition Date and the date that the Company emerges from bankruptcy, including:

| • | Segregation of reorganization items as a separate line in the consolidated statements of operations outside of income from continuing operations.

Debtor-In-Possession

As of December 31, 2020, the Debtors operated as debtors in possession in accordance with the applicable provisions of the Bankruptcy Code. The Bankruptcy Court approved motions filed by the Debtors that were designed primarily to mitigate the impact of the Chapter 11 Cases on the Company’s operations, customers and employees. As a result, the Company conducted normal business activities during 2020 and paid all associated obligations for the period following its bankruptcy filing in the ordinary course of business and was authorized to pay and have paid certain pre-petition obligations, including, among other things, for employee wages and benefits and certain goods and services provided. During the Chapter 11 Cases, transactions outside the ordinary course of business required prior approval of the Bankruptcy Court.

Automatic Stay

Subject to certain specific exceptions under the Bankruptcy Code, the Chapter 11 Cases automatically stayed most judicial or administrative actions against the Debtors and efforts by creditors to collect on or otherwise exercise rights or remedies with respect to pre-petition claims. Absent an order from the Bankruptcy Court, substantially all of the Debtors’ pre-petition liabilities are subject to settlement under the Bankruptcy Code.

Executory Contracts

Subject to certain exceptions, under the Bankruptcy Code, the Debtors may assume, assign, or reject certain executory contracts and unexpired leases subject to the approval of the Bankruptcy Court and certain other conditions. Generally, the rejection of an executory contract or unexpired lease is treated as a pre-petition breach of such executory contract or unexpired lease and, subject to certain exceptions, relieves the Debtors from performing their future obligations under such executory contract or unexpired lease but entitles the contract counterparty or lessor to a pre-petition general unsecured claim for damages caused by such deemed breach. Generally, the assumption of an executory contract or unexpired lease requires the Debtors to cure existing monetary defaults under such executory contract or unexpired lease and provide adequate assurance of future performance. Please refer to Note 15—Commitments and Contingencies — Delivery Commitments for more information.

Potential Claims

The Debtors have filed with the Bankruptcy Court schedules and statements setting forth, among other things, the assets and liabilities of each of the Debtors, subject to the assumptions filed in connection therewith. These schedules and statements may be subject to further amendment or modification after filing. Certain holders of pre-petition claims that are not governmental units were required to file proofs of claim by the bar date of August 14, 2020. As of March 9, 2021, the Debtors’ have received approximately 2,600 proofs of claim, primarily representing general unsecured claims, for an amount of approximately $5.8 billion. The Bankruptcy Court does not allow for claims that have been acknowledged as duplicates. Approximately 1,100 claims totaling approximately $4.2 billion have been withdrawn, disallowed or are pending approval to be disallowed. Differences in amounts recorded and claims filed by creditors will be investigated and resolved, including through the filing of objections with the Bankruptcy Court, where appropriate. The Company may ask the Bankruptcy Court to disallow claims that the Company believes are duplicative, have been later amended or superseded, are without merit, are overstated or should be disallowed for other reasons. In light of the substantial number of claims filed, the claims resolution process may take considerable time to complete and is continuing even after the Debtors emerged from bankruptcy.

Reorganization Items, Net

The Debtors have incurred and will continue to incur significant costs associated with the reorganization, primarily from damages for rejected or settled contracts and legal and professional fees. The amount of these costs, which since the Petition Date, are being expensed as incurred, are expected to significantly affect the Company’s results of operations. In accordance with applicable guidance, costs associated with the bankruptcy proceedings have been recorded as reorganization items within the Company’s accompanying consolidated statements of operations for the year ended December 31, 2020. Please refer to Note 5—Reorganization Items, Net for more information.

Other Operating Expenses

Other operating expenses were $79.6 million for the year ended December 31, 2020. There were no other operating expenses for the year ended December 31, 2019. The total amount in the current year is made up of the following:

| • | $46.8 million loss contingency from an alleged breach in contract stemming from a purported failure to complete the pipeline extensions connecting certain wells to the Badger central gathering facility prior to April 1, 2020. Please see Note 15—Commitments and Contingencies for further details.

| • | $4.2 million of accrued interest related to the aforementioned alleged breach in contract.

| • | $13.2 million early termination penalty for the revenue contract terminated in June 2020. Please see the section Contract Balances below for further details.

| • | $7.6 million of expenses related to workforce reductions in February and May 2020.

| • | $4.1 million of interest expense on unpaid production taxes recorded in the last half of 2020.

| • | $2.4 million of expenses related to drilling rig standby charges during the second quarter of 2020.

| • | $1.3 million of expenses related to legal accruals and other.

Cash and Cash Equivalents

Cash and cash equivalents consist of all highly liquid investments that are readily convertible into cash and have original maturities of three months or less when purchased.

Accounts Receivable

The Company records estimated oil and gas revenue receivable from third parties at its net revenue interest. The Company also reflects costs incurred on behalf of joint interest partners in accounts receivable. The Company generally has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings. On an on-going basis, management reviews accounts receivable amounts for collectability and records its allowance for uncollectible receivables based on expected losses. The Company did not record any allowance for uncollectible receivables as of December 31, 2020 and 2019.

Credit Risk and Other Concentrations

The Company’s cash and cash equivalents are exposed to concentrations of credit risk. The Company manages and controls this risk by investing these funds with major financial institutions. The Company often has balances in excess of the federally insured limits.

The Company sells oil, natural gas and NGL to various types of customers, including oil marketers, pipelines and refineries. Credit is extended based on an evaluation of the customer’s financial conditions and historical payment record. The future availability of a ready market for oil, natural gas and NGL depends on numerous factors outside the Company’s control, none of which can be predicted with certainty. For the years ended December 31, 2020 and 2019, the Company had the following customers that exceeded 10% of total oil, natural gas and NGL revenues. The Company does not believe the loss of any single purchaser would materially impact its operating results because crude oil, natural gas and NGL are fungible products with well-established markets and numerous purchasers.

|  | For the Year Ended December 31, |
|  | 2020 |  |  | 2019 |
Customer A |  |  | 28 | % |  |  | 77 | %
Customer B |  |  | 16 | % |  |  | <10 | %
Customer C |  |  | 12 | % |  |  | <10 | %
Customer D |  |  | <10 | % |  |  | <10 | %

At December 31, 2020, the Company had commodity derivative contracts with two counterparties, both of which are lenders under the Predecessor Credit Agreement. The Company does not require collateral or other security from counterparties to support derivative instruments; however, to minimize the credit risk in derivative instruments, it is the Company’s policy to enter into derivative contracts only with counterparties that are credit worthy financial institutions deemed by management as competent and competitive market-makers. Additionally, the Company uses master netting agreements to minimize credit-risk exposure. The credit worthiness of the Company’s counterparties is subject to periodic review. For the years ended December 31, 2020 and 2019, the Company did not incur any losses with respect to counterparty contracts. None of the Company’s existing derivative instrument contracts contains credit-risk related contingent features.

Inventory, Prepaid Expenses and Other

The Company records well equipment inventory at the lower of cost or net realizable value. Prepaid expenses are recorded at cost. Inventory, prepaid expenses and other are comprised of the following (in thousands):

|  | As of December 31, |
|  | 2020 |  |  | 2019 |
Well equipment inventory |  | $ | 11,989 |  |  | $ | 20,960 |
Prepaid expenses |  |  | 8,456 |  |  |  | 5,793 |
Line fill |  |  | 14,115 |  |  |  | — |
Deposits |  |  | 1,822 |  |  |  | — |
Contractual asset under ASC 606 |  |  | — |  |  |  | 9,949 |
|  | $ | 36,382 |  |  | $ | 36,702 |

The Company recognized impairment expense on well equipment inventory in the amount of $2.1 million for the year ended December 31, 2020. No such impairment expense was recognized for the year ended December 31, 2019.

Oil and Gas Properties

The Company follows the successful efforts method of accounting for oil and gas properties. Under this method of accounting, all property acquisition costs and development costs are capitalized when incurred and depleted on a units-of-production basis over the remaining life of proved reserves and proved developed reserves, respectively. For the years ended

December 31, 2020 and 2019, the Company excluded $129.1 million and $149.7 million, respectively, of capitalized costs from depletion related to wells in progress. For the years ended December 31, 2020 and 2019, the Company recorded depletion expense on capitalized oil and gas properties of $321.0 million and $513.7 million, respectively.

The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that proved reserves have been found. If no proved reserves have been found, the costs of exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. Costs incurred for exploratory wells that find reserves that cannot yet be classified as proved are capitalized if (a) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (b) sufficient progress in assessing the reserves and the economic and operating viability of the project has been made. The status of suspended well costs is monitored continuously and reviewed at each period end. Due to the capital-intensive nature and the geological characteristics of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and the economics associated with making a determination of its commercial viability. As of December 31, 2020 and 2019, the Company had no suspended well costs.

Geological and geophysical costs are expensed as incurred. Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs. Amounts of seismic costs capitalized are based on only those blocks of data used in determining development well locations. To the extent that a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between development costs and exploration expense. The Company expensed $0.2 million of costs associated with exploratory geological and geophysical costs for the both the years ended December 31, 2020 and 2019.

The Company capitalizes interest, if debt is outstanding, during drilling operations in its exploration and development activities. For the years ended December 31, 2020 and 2019, the Company capitalized interest of approximately $5.3 million and $7.2 million, respectively.

Net carrying values of retired, sold or abandoned properties that constitute less than a complete unit of depreciable property are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized in income. Gains or losses from the disposal of complete units of depreciable property are recognized to earnings.

For sales of entire working interests in unproved properties, gain or loss is recognized to the extent of the difference between the proceeds received and the net carrying value of the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of costs unless the proceeds exceed the entire cost of the property.

Impairment of Oil and Gas Properties

Proved oil and gas properties are reviewed for impairment annually or when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. For all of its fields, the Company estimates the expected future cash flows of its oil and gas properties and compares these undiscounted cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will write down the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures, estimated future operating costs, and discount rates commensurate with the risk associated with realizing the projected cash flows. Impairment expense for proved oil and gas properties is reported in impairment of long lived assets and goodwill in the consolidated statements of operations, which increases accumulated depletion, depreciation and amortization. For the year ended December 31, 2020, the Company recognized $3.6 million related to impairment of the proved oil and gas properties in our northern field and $194.3 million related to oil and gas properties in one of our Core DJ Basin fields, as the fields’ fair values did not exceed the carrying amounts associated with our oil and gas properties. For the year ended December 31, 2019, the Company recognized $14.5 million related to impairment of the proved oil and gas properties in its northern field and $1.3 billion related to assets in its Core DJ Basin field as the field’s fair values did not exceed the carrying amounts associated with its proved oil and gas properties.

Unproved oil and gas properties consist of costs to acquire unevaluated leases as well as costs to acquire unproved reserves. The Company evaluates significant unproved oil and gas properties for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage. When successful wells are drilled on undeveloped leaseholds, unproved property costs are reclassified to proved properties and depleted on a unit-of-production basis. Impairment expense and lease extension payments for unproved properties is reported in exploration and abandonment expenses in the consolidated statements of operations. As a result of the abandonment of unproved properties, the Company recognized $253.1 million and $73.7 million of abandonment expense for the years ended December 31, 2020 and 2019, respectively.

Other Property and Equipment

Other property and equipment consists of (i) compressors, compressor stations, central tank batteries and disposal well facilities used in Extraction’s oil and gas operations, (ii) land, (iii) rights of ways, pipeline and engineering costs, (iv) office leasehold improvements, (v) the field office, and (vi) other property and equipment including office furniture and fixtures and computer hardware and software. Impairment expense for other property and equipment is reported in impairment of long lived assets and goodwill in the consolidated statements of operations. No impairment expense was incurred related to midstream facilities for the year ended December 31, 2020. The Company recognized $0.1 million in impairment expense related to midstream facilities for the year ended December 31, 2019, which increased accumulated depreciation recognized in other property and equipment, net of accumulated depreciation. These impairment expenses were primarily the result of right-of-way options that were no longer in the Company’s plans for developing midstream infrastructure. The gain or loss on the sale of other property and equipment is reported in gain (loss) on sale of property and equipment and assets of unconsolidated subsidiary in the consolidated statements of operations. The Company recognized $4.5 million, $3.1 million and $0.8 million of impairment expense related to land, midstream facilities and rental equipment, respectively, for the year ended December 31, 2020. The Company also wrote off $2.6 million of leasehold improvements during the year ended December 31, 2020 due to a consolidation of leased office space.

The estimated useful lives of those assets depreciated under the straight-line method are as follows:

Rental equipment |  |  | 1-10 years |
Office leasehold improvements |  |  | 3-10 years |
Field office |  |  | 30 years |
Other |  |  | 3-5 years |

Other property and equipment is comprised of the following (in thousands):

|  | As of December 31, |
|  | 2020 |  |  | 2019 |
Rental equipment |  | $ | 3,251 |  |  | $ | 4,043 |
Land |  |  | 39,788 |  |  |  | 42,273 |
Right-of-ways and pipeline |  |  | 8,008 |  |  |  | 8,008 |
Office leasehold improvements |  |  | 4,390 |  |  |  | 7,009 |
Field office |  |  | 18,447 |  |  |  | 18,317 |
Other |  |  | 8,604 |  |  |  | 8,884 |
Less: accumulated depreciation and impairment charges |  |  | (25,787 | ) |  |  | (15,992 | )
|  | $ | 56,701 |  |  | $ | 72,542 |

Gathering Systems and Facilities

Gathering systems and facilities consisted of midstream assets such as land, rights of way, pipelines, equipment and construction and engineering costs associated with the construction of pipeline infrastructure to serve the development of the Company’s acreage in its Hawkeye and Southwest Wattenberg areas. As discussed in Note 1 — Business and Organization — Deconsolidation of Elevation Midstream, LLC, during the first quarter of 2020 the Company deconsolidated Elevation Midstream, LLC.

Gathering systems and facilities is comprised of the following (in thousands):

|  | As of December 31, |
|  | 2020 |  |  | 2019 |
Gathering systems and facilities |  | $ | — |  |  | $ | 314,906 |
Land associated with gathering systems and facilities |  |  | — |  |  |  | 2,188 |
Less: accumulated depreciation |  |  | — |  |  |  | (1,317 | )
|  | $ | — |  |  | $ | 315,777 |

Gathering systems and facilities balances are evaluated for potential impairment when events or changes in circumstances indicate that their carrying amounts may not be recoverable from expected undiscounted cash flows from the use and eventual disposition of an asset. If the carrying amount of the asset is not expected to be recoverable from future undiscounted cash flows, an impairment may be recognized. Any impairment is measured as the excess of the carrying amount of the asset over its estimated fair value.

In assessing gathering systems and facilities assets for impairment, management evaluates changes in business and economic conditions and their implications for recoverability of the assets’ carrying amounts. The measure of impairments to be recognized, if any, depends upon management’s estimate of the asset’s fair value, which may be determined based on the estimates of future net cash flows or values at which similar assets were transferred in the market in recent transactions, if such data is available. Gathering systems and facilities are recorded at historical cost and depreciated using the straight-line method over 30 years.

In March 2020, Elevation determined certain gathering systems and facilities were impaired by $50.3 million as a result of the abandonment of certain projects. In accordance with ASC Topic 323-10-35-20: Investments—equity method and joint ventures, Extraction discontinued applying the equity method investment for Elevation as the impairment charge would have reduced the investment below zero. For further information on the deconsolidation of Elevation Midstream, LLC, please see Note 1 - Business and Organization — Deconsolidation of Elevation Midstream, LLC. No impairment expense was recognized for the year ended December 31, 2019 associated with gathering systems and facilities.

Equity Method Investments

Investments in entities for which the Company exercises significant influence, but not control, are accounted for under the equity method of accounting. The Company recognized $0.5 million and $2.3 million of net income from such investments, including the accretion of any basis difference between the carrying amount of the investment and the amount of underlying equity in net assets, included in other income on the consolidated statements of operations and equity in earnings of unconsolidated subsidiary, in which we had a minority ownership interest on the consolidated statements of cash flows for the years ended December 31, 2020 and 2019, respectively.

For the year ended December 31, 2019, a gain on sale of unconsolidated subsidiary of $1.0 million was recorded relating to Elevation’s August 2018 Divestiture. The Company acquired its interest in exchange for the contribution of an acreage dedication, which is considered a nonfinancial asset.

Deferred Lease Incentives

All incentives received from landlords for office leasehold improvements are recorded as deferred lease incentives and amortized over the term of the respective lease on a straight-line basis as a reduction of rental expense. The Company wrote off $2.6 million of leasehold improvements during the year ended December 31, 2020 due to a consolidation of leased office space.

Debt Issuance Costs

Debt issuance costs include origination, legal, engineering, and other fees incurred to issue the debt in connection with the Company’s Prior Credit Facility, DIP Credit Facility (as defined in Note 7 — Long Term Debt), 2024 Senior Notes and 2026 Senior Notes (collectively, the “Senior Notes”). Debt issuance costs related to the Prior Credit Facility are amortized to interest expense on the consolidated statement of operations on a straight-line basis over the respective borrowing term. Debt issuance costs related to the Senior Notes prior to the Chapter 11 Cases were amortized to interest expense using the effective interest method over the term of the debt. However, as a result of the Chapter 11 Cases, the Company expensed $13.5 million of debt issuance costs pertaining to the Senior Notes to reorganization items, net on the consolidated statements of operations for the year ended December 31, 2020. Debt issuance costs of $1.7 million pertaining to the DIP Credit Facility were expensed to reorganization items, net during the year ended December 31, 2020.

Commodity Derivative Instruments

The Company has entered into commodity derivative instruments to reduce the effect of price changes on a portion of the Company’s future oil and natural gas production. The commodity derivative instruments are measured at fair value. The Company has not designated any of the derivative contracts as fair value or cash flow hedges. Therefore, the Company does not apply hedge accounting to the commodity derivative instruments. Net gains and losses on commodity derivative instruments are recorded based on the changes in the fair values of the derivative instruments. Net gains and losses on commodity derivative instruments are recorded in the commodity derivatives gain (loss) line on the consolidated statements of operations. The Company’s cash flow is only impacted when the actual settlements under the commodity derivative contracts result in making or receiving a payment to or from the counterparty. These settlements under the commodity derivative contracts are reflected as operating activities in the Company’s consolidated statements of cash flows.

Any premiums paid on derivative contracts are capitalized as part of the derivative assets or derivative liabilities, as appropriate, at the time the premiums are paid. Premium payments are reflected in cash flows from operating activities in the Company’s consolidated statements of cash flows. Over time, as the derivative contracts settle, the differences between the cash received and the premiums paid or fair value of contracts acquired are recognized in net gains or losses on commodity or interest rate derivative contracts, and the cash received is reflected in cash flows from operating activities in the Company’s consolidated statements of cash flows.

The Company’s valuation estimate takes into consideration the counterparties’ credit worthiness, the Company’s credit worthiness, and the time value of money. The consideration of these factors results in an estimated exit-price for each derivative asset or liability under a market participant’s view. Management believes that this approach provides a reasonable, non-biased, verifiable, and consistent methodology for valuing commodity derivative instruments. Please refer to Note 8 — Commodity Derivative Instruments for additional discussion on commodity derivative instruments.

Other Intangible Assets

Costs relating to the acquisition of internal-use software licenses are capitalized when incurred and amortized over the estimated useful life of the license, which is typically one to three years. Accumulated amortization for the years ended December 31, 2020 and 2019 was $6.8 million and $5.3 million, respectively. The Company recognized $1.6 million and $2.2 million of amortization expense for the years ended December 31, 2020 and 2019, respectively.

Fair Value of Financial Instruments

The Company’s financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable, commodity derivative instruments (discussed above) and long-term debt. The carrying values of cash and cash equivalents, accounts receivable and accounts payable are representative of their fair values due to their short-term maturities. The carrying amounts of the Company’s Prior Credit Facility and DIP Credit Facility approximates fair value as it bears interest at variable rates over the term of the loans. The Company’s Senior Notes are recorded at cost and the fair value is disclosed in Note 10 — Fair Value Measurements. Considerable judgment is required to develop estimates of fair value. The estimates provided are not necessarily indicative of the amounts the Company would realize upon the sale or refinancing of such instruments.

Asset Retirement Obligation

The Company recognizes estimated liabilities for future costs associated with the abandonment of its oil and gas properties. A liability for the fair value of an asset retirement obligation and corresponding increase to the carrying value of the related long-lived asset are recorded at the time the Company makes the decision to complete the well or a well is acquired. For additional discussion on asset retirement obligations please refer to Note 9 — Asset Retirement Obligations.

Environmental Liabilities

The Company is subject to federal, state and local environmental laws and regulations. These laws regulate the release, disposal or discharge of materials into the environment or otherwise relating to environmental protection and may require the Company to remove or mitigate the environmental effects of the discharge, disposal or release of petroleum substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed.

Liabilities for expenditures of a non-capital nature are recorded when environmental assessments and/or remediation is probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted values unless the timing of cash payments for the liability or component is fixed or determinable. Management has determined that no significant environmental liabilities existed as of December 31, 2020. Please refer to Note 15 — Commitments and Contingencies for additional discussion on environmental liabilities.

Revenue Recognition

Revenue from the sale of oil, natural gas and NGLs is recognized in accordance with ASC 606 - Revenue from Contracts with Customers (“ASC 606”) five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. To account for producer imbalances, the Company recognizes revenues on all sales of oil, natural gas and NGLs to third party customers regardless of their ownership percentage and adjusts the underlifter or overlifter’s claim on the asset’s remaining reserves. In other words, revenue is recorded based on the Company’s share of volume sold, regardless of whether the Company has taken its proportional share of volume produced. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than the expected remaining proved reserves. As of December 31, 2020 and 2019, the Company had oil imbalances of 1.1 and 12.7, respectively, which the Company intends to settle with the counterparty in crude oil barrels.

Stock-Based Payments

The Company has granted awards under the LTIP to certain directors, officers and employees, including stock options, restricted stock units, performance stock awards, performance stock units, performance cash awards and cash awards which therefore required the Company to recognize the expense in its consolidated financial statements.

All stock-based payments to directors, officers and employees are measured at fair value on the grant date and expensed over the relevant service period. The fair value of stock option awards is determined by using the Black-Scholes option pricing model. The fair value of the performance stock awards was measured at the grant date with a stochastic process method using a Monte Carlo simulation. All stock-based payment expense is recognized using the straight-line method and is included within general and administrative expenses in the consolidated statements of operations and stock-based compensation in the consolidated statements of cash flows. Forfeitures are recorded as they occur. Please refer to Note 13 — Stock-Based Compensation for additional discussion on stock-based payments.

Income Taxes

The Company accounts for income taxes using the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and operating loss and tax credit carry forwards. Deferred tax assets and liabilities are calculated by applying existing tax laws and the rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date. The tax returns and the amount of taxable income or loss are subject to examination by deferral and state taxing authorities.

The Company periodically assesses whether it is more likely than not that it will generate sufficient taxable income to realize its deferred income tax assets, including NOLs. In making this determination, the Company considers all the available positive and negative evidence and makes certain assumptions. The Company considers, among other things, its deferred tax liabilities, the overall business environment, its historical earnings and losses, current industry trends, and its outlook for future years. The Company believes it is more likely than not that the benefit from NOL carryforwards will not be fully realized. In recognition of this risk, the Company has provided a valuation allowance on the deferred tax assets.

The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. The tax benefits recognized in the consolidated financial statements from such a position are measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. The Company does not currently have uncertain tax positions.

Earnings Per Share

Basic earnings per share (“EPS”) includes no dilution and is computed by dividing net income (loss) available to common shareholders by the weighted-average number of shares outstanding during the period. Diluted EPS reflects the potential dilution of securities that could share in the earnings available to common shareholders of the Company. The Company uses the “if-converted” method to determine the potential dilutive effects of its Series A Preferred Stock, and the treasury stock method to determine the potential dilutive effect of outstanding restricted stock units and stock option awards.

Segment Reporting

Beginning in the fourth quarter of 2018, the Company had two operating segments, (i) the exploration, development and production of oil, natural gas and NGL (the “exploration and production segment”) and (ii) the construction of and support of midstream assets to gather and process crude oil and gas production (the “gathering and facilities segment”). Elevation Midstream, LLC comprised the gathering and facilities segment. During the fourth quarter of 2019, the Company’s gathering and facilities segment commenced operations. Through March 16, 2020, the results of Elevation were included in the consolidated financial statements of Extraction. Effective March 17, 2020, the results of Elevation Midstream, LLC are no longer consolidated in Extraction’s results; however, the Company’s prior annual segment disclosures included the gathering and facilities segment because it was consolidated through March 16, 2020. Please see Note 1 — Business and Organization — Deconsolidation of Elevation Midstream, LLC for further information related to the deconsolidation of Elevation Midstream, LLC. After March 16, 2020, the Company had a single reportable segment.

All of the Company’s operations are conducted in one geographic area of the United States. All revenues are derived from customers located in the United States.

Recent Accounting Pronouncements

The accounting standard-setting organizations frequently issue new or revised accounting rules. The Company regularly reviews new pronouncements to determine their impact, if any, on its consolidated financial statements and related disclosures.

In March 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2020-04, Reference Rate Reform — Facilitation of the Effects of Reference Rate Reform on Financial Reporting (Topic 848). This ASU provides an optional expedient and exceptions for applying GAAP to contracts, hedging relationships, and other transactions affected by reference rate reform if certain criteria are met. In response to the concerns about structural risks of interbank offered rates (IBORs) and, particularly, the risk of cessation of the London Interbank Offered Rate (LIBOR), regulators in several jurisdictions around the world have undertaken reference rate reform initiatives to identify alternative reference rates that are more observable or transaction-based and less susceptible to manipulation. The ASU provides companies with optional guidance to ease the potential accounting burden associated with transitioning away from reference rates that are expected to be discontinued. In January 2021, the FASB issued ASU No. 2021-01, which clarifies that certain provisions in Topic 848, if elected by an entity, apply to derivative instruments that use an interest rate for margining, discounting, or contract price alignment that is modified as a result of reference rate reform. The amendments in these ASUs are effective for all entities as of March 12, 2020 through December 31, 2022. The Company is still evaluating the effect of adopting this guidance.

In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments—Credit Losses. In May 2019, ASU No. 2016-13 was subsequently amended by ASU No. 2019-04, Codification Improvements to Topic 326, Financial Instruments—Credit Losses and ASU No. 2019-05, Financial Instruments—Credit Losses (Topic 326): Targeted Transition Relief. ASU No. 2016-13, as amended, affects trade receivables, financial assets and certain other instruments that are not measured at fair value through net income. This ASU replaced the incurred loss approach with an expected loss model for instruments measured at amortized cost and was effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. ASU No. 2016-13 will be applied using a modified retrospective approach through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. The Company adopted this ASU on January 1, 2020, and the adoption did not have a material impact on the consolidated financial statements and related disclosures.

In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurement (Topic 820) which removes or modifies current fair value disclosures and adds additional disclosures. The update to the guidance is the result of the FASB’s test of the principles developed in its disclosure effectiveness project, which is designed to improve the effectiveness of disclosures in the notes to the financial statements. The disclosures that have been removed or modified may be applied immediately with retrospective application. For public entities, the new guidance was effective for fiscal years beginning after December 15, 2019, including interim reporting periods within that reporting period. The Company adopted this ASU on January 1, 2020, and the adoption did not have a material impact on the consolidated financial statements and related disclosures.

In August 2018, the FASB issued ASU No. 2018-15, Intangibles - Goodwill and Other - Internal-Use Software (Subtopic 350-40) which aligns the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software and hosting arrangements that include an internal-use software license. For public entities, the guidance is effective for fiscal years beginning after December 15, 2019, including interim reporting periods within that reporting period. The Company adopted this ASU on January 1, 2020 which did not have a material impact on the consolidated financial statements and related disclosures as capitalized costs for internal-use software were not material during 2020.

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) which requires lessee recognition on the balance sheet of a right of use asset and a lease liability, initially measured at the present value of the lease payments. It further requires recognition in the income statement of a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a generally straight-line basis. Under the new standard, certain lease agreements with terms over one year are classified as right-of-use assets and right-of-use liabilities, which gross up the balance sheet. Finally, it requires classification of all cash payments within operating activities in the statements of cash flows. It is effective for fiscal years commencing after December 15, 2018. The FASB subsequently issued ASU No. 2017-13, ASU No. 2018-01, ASU No. 2018-10 and ASU No. 2018-11, which provided additional implementation guidance. The Company adopted these lease accounting standards on January 1, 2019 using a modified retrospective transition approach, which applied the provisions of the new guidance at the effective date without adjusting the comparative periods presented. Upon adoption, the Company elected the package of practical expedients permitted under the transition guidance with the new standard, which among other things, requires no reassessment of whether existing contracts are or contain leases as well as no reassessment of lease classification for existing leases upon adoption. The Company also elected the optional practical expedient permitted under the transition guidance within the new standard related to land easements that allows it to carry forward its current accounting treatment for land easements on existing agreements. The Company made an accounting policy election to keep leases with an initial term of twelve months or less off of the consolidated balance sheets. Please refer to Note 6 — Leases for further information.

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) which establishes a comprehensive new revenue recognition model, referred to as ASC 606, designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. The ASU allows for the use of either the full or modified retrospective transition method. In August 2015, the FASB issued ASU No. 2015-14, which deferred ASU No. 2014-09 for one year, and was effective for annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. The FASB subsequently issued ASU No. 2016-08, ASU No. 2016-10, ASU No. 2016-11, ASU No. 2016-12, ASU No. 2016-20, ASU No. 2017-13, ASU No. 2017-14 and ASU No. 2019-20, which provided additional implementation guidance.

Revenues from Contracts with Customers

Sales of oil, natural gas and NGLs are recognized at the point control of the commodity is transferred to the customer and collectability is reasonably assured. The majority of the Company’s contracts’ pricing provisions are tied to a commodity market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and prevailing supply and demand conditions. As a result, the price of the oil, natural gas and NGLs fluctuates to remain competitive with the other available oil, natural gas and NGL supplies.

Oil Sales

Under the Company’s crude purchase and marketing contracts, the Company generally sells oil production at the wellhead and collects an agreed-upon index price, net of pricing differentials. In this scenario, the Company recognizes revenue when control transfers to the purchaser at the wellhead at the net price received.

To account for producer imbalances, the Company recognizes revenue on all sales to third party customers regardless of their ownership percentage and adjusts the underlifter or overlifter’s claim on the asset’s remaining reserves. As of December 31, 2020, the Company had an oil imbalance of 1.1 MBbl, which the Company intends to settle with the counterparty in crude oil barrels.

Natural Gas and NGL Sales

Under the Company’s natural gas processing contracts, the Company delivers natural gas to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of NGLs and residue gas. In these scenarios, we evaluate whether we are the principal or the agent in the transaction, and the point at which control of the hydrocarbons transfers to the customer. For those contracts where the Company has concluded the midstream processing entity is the Company’s agent and the third-party end user is its customer (generally the Company’s fixed-fee gathering and processing agreements), the Company recognizes revenue on a gross basis, with transportation and gathering expense presented as an operating expense in the consolidated statements of operations. Alternatively, for those contracts where the Company has concluded the midstream processing entity is its customer and controls the hydrocarbons (generally the Company’s percentage of proceeds gathering and processing agreements), the Company recognizes natural gas and NGL revenues based on the net amount of the proceeds received from the midstream processing company.

In certain natural gas processing agreements, the Company may elect to take its residue gas and/or NGLs in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. Through the marketing process, the Company delivers product to the third-party purchaser at a contractually agreed-upon delivery point and receives a specified index price from the purchaser. In this scenario, the Company recognizes revenue when the control transfers to the purchaser at the delivery point based on the index price received from the purchaser. The gathering and processing expense attributable to the gas processing contracts, as well as any transportation expense incurred to deliver the product to the purchaser, are presented as transportation and gathering expense in the consolidated statements of operations.

Performance Obligations

A significant number of the Company’s product sales are short-term in nature with a contract term of one year or less. For those contracts, the Company has utilized the practical expedient in ASC 606-10-50-14 exempting the Company from disclosure of the transaction price of a contract that has an original expected duration of one year or less.

For the Company’s product sales that have a contract term greater than one year, the Company has utilized the practical expedient in ASC 606-10-50-14(a), which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

The Company records revenue on its oil, natural gas and NGL sales at the time production is delivered to the purchaser. However, settlement statements for certain oil, natural gas and NGL sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the customer and the net commodity price that will be received for the sale of these commodity products. The Company records the differences between the revenue estimated and the actual amounts received for product sales in the month that payment is received from the customer.

Contract Balances

The Company had a certain revenue contract with an initial term beginning on November 1, 2016 and continuing until October 31, 2020 after which the contract was to begin an automatic month-to-month renewal unless terminated by either party giving notice at least six months prior to the effective termination date but in no event could either party give such notice earlier than November 1, 2020. Based on the accounting treatment pursuant to ASC 606 — Revenue from Contracts with Customers, the contract term would end on April 30, 2021 because it could be terminated by either party with no penalty effective as of such date. The contract term impacted the amount of consideration that could be included in the transaction price. The Company recognizes revenue and invoices customers once its performance obligations have been satisfied. When it becomes probable that the Company will not meet its performance obligations, the transaction price allocated to the performance obligation is constrained in the amount of the estimated unmet performance obligation and recognized as a reduction to revenue in the period in which the transaction price changes. On June 12, 2020, the Company and the counterparty to the contract mutually cancelled the contract effective June 30, 2020. As a result of the cancellation, for the year ended December 31, 2020, $12.3 million was recorded as a reduction in the transaction price resulting from unsatisfied performance obligations in the period. For the year ended December 31, 2019, the Company allocated $24.7 million to a satisfied performance obligation recognized within oil sales under ASC 606. As a result of the contract termination, the Company incurred an early termination fee of $13.2 million recorded in other operating expenses for the year ended December 31, 2020. This amount was settled during the third quarter of 2020, and there are no remaining amounts due to the counterparty.

The following table presents the Company’s revenues disaggregated by revenue source. Transportation and gathering costs in the following table are not all of the transportation and gathering expenses that the Company incurs, only the expenses that are netted against revenues pursuant to ASC 606.

|  | For the Year Ended December 31, |
|  | 2020 |  |  | 2019 |
Revenues: |  |  |  |  |  |  |  |
Oil sales |  | $ | 382,526 |  |  | $ | 721,429 |
Natural gas sales |  |  | 114,786 |  |  |  | 129,969 |
NGL sales |  |  | 89,634 |  |  |  | 92,429 |
Gathering and compression |  |  | 1,473 |  |  |  | 1,261 |
Transportation and gathering included in revenues |  |  | (30,515 | ) |  |  | (38,453 | )
Total Revenues |  | $ | 557,904 |  |  | $ | 906,635 |

There are no other accounting standards applicable to the Company that have been issued but not yet adopted by the Company as of December 31, 2020 and through the date of this filing that would have a material impact on the Company’s consolidated financial statements and related disclosures.

Note 3—Oil and Gas Properties

The Company’s oil and gas properties are entirely within the United States. The net capitalized costs related to the Company’s oil and gas producing activities were as follows (in thousands):

|  | As of December 31, |
|  | 2020 |  |  | 2019 |
Proved oil and gas properties |  | $ | 4,743,463 |  |  | $ | 4,530,934 |
Unproved oil and gas properties (1) |  |  | 220,380 |  |  |  | 524,214 |
Wells in progress (2) |  |  | 129,058 |  |  |  | 149,733 |
Total capitalized costs (3) |  | $ | 5,092,901 |  |  | $ | 5,204,881 |
Accumulated depletion, depreciation, amortization and impairment charge (4) |  | $ | (3,459,689 | ) |  |  | (2,985,983 | )
Net capitalized costs |  | $ | 1,633,212 |  |  | $ | 2,218,898 |

(1) Unproved oil and gas properties represent unevaluated costs the Company excludes from the amortization base until proved reserves are established or impairment is determined.

(2) Costs from wells in progress are excluded from the amortization base until production commences.

(3) Includes accumulated interest capitalized of $45.1 million and $39.8 million as of December 31, 2020 and 2019, respectively.

(4) For more information about proved oil and gas properties impairment, see Note 2 — Basis of Presentation and Significant Accounting Policies.

1

The following table presents information regarding the Company’s net costs incurred in oil and gas property acquisition, exploration and development activities (in thousands):

|  | For the Year Ended |
|  | December 31, |
|  | 2020 |  |  | 2019 |
Property acquisition costs: |  |  |  |  |  |  |  |
Proved |  | $ | 8,071 |  |  | $ | 21,024 |
Unproved |  |  | 8,970 |  |  |  | 35,207 |
Exploration costs (1) |  |  | — |  |  |  | 3,569 |
Development costs |  |  | 173,538 |  |  |  | 588,974 |
Total |  | $ | 190,579 |  |  | $ | 648,774 |
Total excluding asset retirement costs |  | $ | 176,629 |  |  | $ | 598,778 |

(1) Exploration costs do not include abandonment costs of unproved properties, which are included in the line item exploration and abandonment expenses in the consolidated statements of operations.

Note 4—Acquisitions and Divestitures

February 2020 Divestiture

In February 2020, the Company completed the sale of certain non-operated producing properties for aggregate sales proceeds of approximately $12.2 million, subject to customary purchase price adjustments. No gain or loss was recognized for the February 2020 Divestiture. The Company continues to explore divestitures, as part of our ongoing initiative to divest of non-strategic assets.

December 2019 Divestiture

In December 2019, the Company completed the sale of certain non-operated producing properties for aggregate sales proceeds of approximately $10.0 million, subject to customary purchase price adjustments. No gain or loss was recognized for the December 2019 Divestiture.

August 2019 Divestiture

In August 2019, the Company completed the sale of certain non-operated producing properties for aggregate sales proceeds of approximately $22.0 million, subject to customary purchase price adjustments. No gain or loss was recognized for the August 2019 Divestiture.

March 2019 Divestiture

In March 2019, the Company completed the sale of its interests in approximately 5,000 net acres of leasehold and producing properties for aggregate sales proceeds of approximately $22.4 million. The effective date for the March 2019 Divestiture was July 1, 2018 with purchase price adjustments calculated as of the closing date of $5.9 million, resulting in net proceeds of $16.5 million. No gain or loss was recognized for the March 2019 Divestiture.

Note 5— Reorganization Items, Net

The Company’s reorganization items, net consisted of the following (in thousands):

|  | For the Year Ending |
|  | December 31, 2020 |
Professional fees |  | $ | 59,841 |
Professional services fees |  |  | 2,200 |
Trustee fees |  |  | 801 |
Damages for rejected and settled contracts |  |  | 572,126 |
DIP Credit Facility fees |  |  | 1,717 |
Write-off of debt issuance costs |  |  | 13,541 |
Court approved vendor settlements |  |  | (2,602 | )
Backstop commitment premium |  |  | 29,231 |
Total reorganization items, net |  | $ | 676,855 |

The Company has incurred and will continue to incur significant expenses, gains and losses associated with the reorganization, primarily adjustments for allowable claims related to executory contracts approved for rejection by the Bankruptcy Court, negotiated settlements on executory contracts, the write-off of unamortized debt issuance costs and professional fees incurred subsequent to the Chapter 11 filings for the restructuring process. The amount of these items, which are being incurred in reorganization items, net within the Company’s accompanying consolidated statements of operations, are expected to significantly affect the Company’s results of operations.

The write-off of the Senior Notes debt issuance costs are included in reorganization items, net as the underlying debt instruments were impacted by the Chapter 11 Cases. The write-off of the Senior Notes debt issuance costs is a non-cash reorganization item. For the year ended December 31, 2020, the Company had cash charges related to reorganization items, net of $34.4 million.

Note 6—Leases

The Company accounts for leases in accordance with ASC 842, Leases, which it adopted on January 1, 2019, applying the modified retrospective transition approach as of the effective date of adoption (see Note 2 — Basis of Presentation and Significant Accounting Policies — Recent Accounting Pronouncements for impacts of adoption).

The Company enters into operating leases for certain drilling equipment, completions equipment, equipment ancillary to drilling and completions, office facilities, compressors and office equipment. Under ASC 842, a contract is or contains a lease when (i) the contract contains an explicitly or implicitly identified asset and (ii) the customer obtains substantially all of the economic benefits from the use of that underlying asset and directs how and for what purpose the asset is used during the term of the contract in exchange for consideration. The Company assesses whether an arrangement is or contains a lease at inception of the contract. All leases (operating leases), other than those that qualify for the short-term recognition exemption, are recognized as of the lease commencement date on the balance sheet as a liability for its obligation related to the lease and a corresponding asset representing its right to use the underlying asset over the period of use.

The Company’s leases have remaining terms up to four years. Certain of our lease agreements contain options to extend or early terminate the agreement. The lease term used to calculate the lease asset and liability at commencement includes options to extend or terminate the lease when it is reasonably certain that we will exercise that option. When determining whether it is reasonably certain that the Company will exercise an option at commencement, it considers various economic factors, including capital expenditure strategies, the nature, length, and underlying terms of the agreement, as well as the uncertainty of the condition of leased equipment at the end of the lease term. Based on these determinations, the Company generally determines that the exercise of renewal options would not be reasonably certain in determining the expected lease term for leases, other than certain operating compressor leases.

The discount rate used to calculate the present value of the future minimum lease payments is the rate implicit in the lease, when readily determinable. As the Company’s leases generally do not provide an implicit rate, the Company uses its incremental borrowing rate based on its Prior Credit Facility, which includes consideration of the nature, term, and geographic location of the leased asset.

Certain of the Company’s leases include variable lease payments, including payments that depend on an index or rate, as well as variable payments for items such as property taxes, insurance, maintenance, and other operating expenses associated with leased assets. Payments that vary based on an index or rate are included in the measurement of the Company’s lease assets and liabilities at the rate as of the commencement date. All other variable lease payments are excluded from the measurement of the Company’s lease assets and liabilities and are recognized in the period in which the obligation for those payments is incurred. The Company’s lease agreements do not contain any material residual value guarantees or material restrictive covenants.

The Company has elected, for all classes of underlying assets, to not apply the balance sheet recognition requirements of ASC 842 to leases with a term of one year or less, and instead, recognize the lease payments in the consolidated statements of operations on a straight-line basis over the lease term. The Company has also made the election, for its certain drilling equipment, completions equipment, equipment ancillary to drilling and completions, compressors and office equipment classes of underlying assets, to account for lease and non-lease components in a contract as a single lease component.

For the year ended December 31, 2020, lease costs, which represent the straight-line lease expense of right-of-use (“ROU”) assets and short-term leases, were as follows (in thousands):

|  | For the Year Ended December 31, |
|  | 2020 |  |  | 2019 |
Lease Costs included in the Consolidated Statements of Operations |  |  |  |  |  |
Operating lease costs (2) |  | $ | 23,060 |  |  | $ | 33,025 |
General and administrative expenses (3) |  | $ | 3,074 |  |  | $ | 3,821 |
Total operating lease costs |  | $ | 26,134 |  |  | $ | 36,846 |
Total lease costs |  | $ | 95,238 |  |  | $ | 296,583 |

(1) Represents short-term lease capital expenditures related to drilling rigs, completions equipment and other equipment ancillary to the drilling and completion of wells.

(2) Includes $6.0 million and $8.8 million of lease costs accounted for under ASC 842 for the years ended December 31, 2020 and 2019, respectively.

(3) Includes $1.0 million and $1.4 million of lease costs accounted for under ASC 842 for the years ended December 31, 2020 and 2019, respectively.

Supplemental cash flow information related to operating leases for the years ended December 31, 2020 and 2019, was as follows (in thousands):

|  | For the Year Ended December 31, |  |  | For the Year Ended December 31, |
|  | 2020 |  |  | 2019 |
Cash paid for amounts included in the measurements of lease liabilities |  |  |  |  |  |  |  |
Operating cash flows from operating leases |  | $ | 14,146 |  |  | $ | 12,923 |
Right-of-use assets obtained in exchange for lease obligations |  |  |  |  |  |  |  |
Operating leases |  | $ | 5,057 |  |  | $ | 12,805 |

Supplemental balance sheet information related to operating leases were as follows (in thousands, except lease term and discount rate):

|  | 2020 Classification |  | As of December 31, 2020 |  |  | As of December 31, 2019 |
Operating Leases |  |  |  |  |  |  |  |  |  |
Operating lease right-of-use assets |  | Other non-current assets |  | $ | 8,199 |  |  | $ | 29,186 |
Operating lease obligation - short-term |  | Liabilities subject to compromise |  |  | 4,279 |  |  |  | 17,388 |
Operating lease obligation - long-term |  | Liabilities subject to compromise |  |  | 4,357 |  |  |  | 17,166 |
Total operating lease liabilities |  |  |  | $ | 8,636 |  |  | $ | 34,554 |
Weighted Average Remaining Lease Term in Years |  |  |  |  |  |  |  |  |  |
Operating leases |  |  |  |  | 2.3 |  |  |  | 4.4 |
Weighted Average Discount Rate |  |  |  |  |  |  |  |  |  |
Operating leases |  |  |  |  | 4.5 | % |  |  | 4.2 | %

Note 7—Long-Term Debt

The Company’s long-term debt consisted of the following (in thousands):

|  | As of December 31, |
|  | 2020 |  |  | 2019 |
DIP Credit Facility |  | $ | 106,727 |  |  | $ | — |
Prior Credit Facility due August 16, 2022 (or an earlier time as set forth in the credit facility) |  |  | 453,747 |  |  |  | 470,000 |
2024 Senior Notes due May 15, 2024 |  |  | 400,000 |  |  |  | 400,000 |
2026 Senior Notes due February 1, 2026 |  |  | 700,189 |  |  |  | 700,189 |
Total principal |  |  | 1,660,663 |  |  |  | 1,570,189 |
Unamortized debt issuance costs on Senior Notes (1) |  |  | — |  |  |  | (14,412 | )
Total debt, prior to reclassification to liabilities subject to compromise |  |  | 1,660,663 |  |  |  | 1,555,777 |
Less amounts reclassified to liabilities subject to compromise (2) |  |  | (1,100,189 | ) |  |  | — |
Total debt not subject to compromise (3) |  |  | 560,474 |  |  |  | 1,555,777 |
Less: current portion of long-term debt |  |  | (560,474 | ) |  |  | — |
Total long-term debt, net of current portion |  | $ | — |  |  | $ | 1,555,777 |

(1) As a result of the Chapter 11 Cases and the adoption of ASC 852, the Company wrote off all unamortized debt issuance cost balances to reorganization items, net in the consolidated statements of operations during the year ended December 31, 2020.

(2) Debt subject to compromise includes the principal balances of the Company’s Senior Notes, which are unsecured claims in the Chapter 11 Cases and where the payments are stayed.

(3) Debt not subject to compromise includes all borrowings outstanding under the Prior Credit Facility and DIP Credit Facility which are fully secured claims in the Chapter 11 Cases and are expected to be unimpaired.

RBL Credit Facility

On the Emergence Date at emergence, pursuant to the terms of the Plan, the Successor Company entered into a $1.0 billion reserve-based credit agreement (“RBL Credit Agreement”) with Wells Fargo Bank, National Association (“RBL Credit Facility”) with an initial borrowing base of $500.0 million. The borrowing base will be redetermined semiannually on or around May 1 and November 1 of each year, with one interim “wildcard” redetermination available to each of the Company and the bank between scheduled redeterminations during any 12-month period. The next scheduled redetermination will be on or around May 1, 2021. The initial elected amount under the RBL Credit Facility is $500.0 million before giving effect to any outstanding letters of credit.

As of the date of this filing, the Company has drawn $253.7 million on the RBL Credit Facility. Total funds available for borrowing under the Company’s RBL Credit Facility, after giving effect to an aggregate of $0.5 million of undrawn letters of credit, were $245.8 million as of the date of this filing.

The RBL Credit Facility provides for a $50.0 million sublimit of the aggregate commitments that is available for the issuance of letters of credit. The RBL Credit Facility bears interest either at a rate equal to (a) LIBOR plus an applicable margin that varies from 3.00% to 4.00% per annum or (b) a base rate plus an applicable margin that varies from 2.00% to 3.00% per annum. The RBL Credit Facility matures on July 20, 2024. The grid below shows the base rate margin and eurodollar margin depending on the applicable borrowing base utilization percentage as of the date of this filing:

RBL Credit Facility Borrowing Base Utilization Grid

|  |  |  | Base Rate |  |  | Eurodollar |  |  | Commitment |
Borrowing Base Utilization Percentage |  | Utilization |  | Margin |  |  | Margin |  |  | Fee Rate |
Level 1 |  | <25% |  |  | 2.00 | % |  |  | 3.00 | % |  |  | 0.50 | %
Level 2 |  | ≥ 25% < 50% |  |  | 2.25 | % |  |  | 3.25 | % |  |  | 0.50 | %
Level 3 |  | ≥ 50% < 75% |  |  | 2.50 | % |  |  | 3.50 | % |  |  | 0.50 | %
Level 4 |  | ≥ 75% < 90% |  |  | 2.75 | % |  |  | 3.75 | % |  |  | 0.50 | %
Level 5 |  | ≥90% |  |  | 3.00 | % |  |  | 4.00 | % |  |  | 0.50 | %

The RBL Credit Facility requires the Company to maintain (i) a consolidated net leverage ratio of less than or equal to 3.00 to 1.00 and (ii) a consolidated current ratio of greater than or equal to 1.00 to 1.00.

The Company is required to pay a commitment fee of 0.50% per annum on the actual daily unused portion of the current aggregate commitments under the RBL Credit Facility. The Company is also required to pay customary letter of credit and fronting fees.

The RBL Credit Agreement also contains customary affirmative and negative covenants, including, among other things, as to compliance with laws (including environmental laws and anti-corruption laws), delivery of quarterly and annual financial statements and borrowing base certificates, conduct of business, maintenance of property, maintenance of insurance, restrictions on the incurrence of liens, indebtedness, asset dispositions, restricted payments, and other customary covenants.

Additionally, the RBL Credit Agreement contains customary events of default and remedies for credit facilities of this nature. If the Company does not comply with the financial and other covenants in the RBL Credit Agreement, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the RBL Credit Agreement and any outstanding unfunded commitments may be terminated.

Chapter 11 Cases and Effect of Automatic Stay

On June 14, 2020, the Company filed for relief under Chapter 11 of the Bankruptcy Code. The commencement of a voluntary proceeding in bankruptcy constituted an immediate event of default under the Predecessor Credit Agreement and the indentures governing the Company’s Senior Notes, resulting in the automatic and immediate acceleration of all of the Company’s outstanding debt under the Predecessor Credit Agreement and Senior Notes. In conjunction with the filing of the Chapter 11 Cases, the Company did not make the $14.8 million interest payment on the Company’s 2024 Senior Notes (as defined below) due on May 15, 2020.

Debtor-in-Possession Financing

On June 16, 2020, in connection with the filing of the Chapter 11 Cases, the Debtors entered into a debtor-in-possession credit agreement on the terms set forth in a Superpriority Senior Secured Debtor-in-Possession Credit Agreement (the “DIP Credit Agreement”), by and among the Company, as borrower, the Company’s subsidiaries party thereto, as guarantors, the lenders party thereto (the “DIP Lenders”), and Wells Fargo Bank, National Association, as DIP agent and issuing lender, pursuant to which, having been granted the approval of the Bankruptcy Court, the DIP Lenders agreed to provide the Company with a superpriority senior secured debtor-in-possession credit facility (as amended, the “DIP Credit Facility”) with loans in an aggregate principal amount not to exceed $50.0 million that, among other things, will be used to finance the ongoing general corporate needs of the Debtors during the course of the Chapter 11 Cases. In addition to the $50.0 million of incremental loans, the DIP Credit Facility included $75.0 million in Prior Credit Facility loans rolled over into the DIP Credit Facility during July 2020, for a total facility size of $125.0 million.

As is described above, $22.5 million rolled from the Prior Credit Facility to the DIP Credit Facility on June 16, 2020 and an additional $52.5 million rolled on July 20, 2020 upon the Bankruptcy Court’s authorization order (the “Final DIP Order”). On July 27, 2020, the Company drew an additional $20.0 million on the DIP Credit Facility leaving $15.0 million of availability on the facility. As of December 31, 2020, the Company’s DIP Credit Facility borrowings were $35.0 million and $75.0 million had been rolled over from the Prior Credit Facility. As of December 31, 2020, the Company had a undrawn standby letters of credit of $3.5 million under the DIP Credit Facility, which reduced the availability of the undrawn borrowing base. As of December 31, 2020, the total outstanding balance under the DIP Credit Facility was $106.7 million due to land sale proceeds during the fourth quarter that were required to reduce the DIP Credit Facility per the DIP Credit Agreement.

The annualized, weighted average interest rate for the DIP Credit Facility for the year ending December 31, 2020 was approximately 6.75%.

Upon emergence from bankruptcy on the Emergence Date, the DIP Credit Agreement was terminated and the holders of claims under the DIP Credit Agreement received payment in full, in cash, for allowed claims. Also on this date all liens and security interests granted to secure such obligations were automatically terminated and are of no further force and effect.

Predecessor Credit Agreement

As described in Note 1 — Business and Organization — Plan, Disclosure Statement, and Backstop Commitment Agreement, the Company entered into the Predecessor Credit Agreement and subsequent amendments thereto (“Prior Credit Facility”). The acceleration of the obligations under the Predecessor Credit Agreement as of June 14, 2020 resulted in a cross-default and acceleration of the maturity of the Company’s other outstanding long-term debt. As of December 31, 2020, the Prior Credit Facility had a drawn balance of $453.7 million.Because this debt was fully secured, adequate protection payments paid throughout 2020 were classified as interest expense and not a reduction of principal. As is described in the Debtor-in-Possession Financing section above, $22.5 million rolled from the Prior Credit Facility to the DIP Credit Facility on June 16, 2020 and an additional $52.5 million rolled on July 20, 2020 upon court approval of the Final DIP Order. During the third quarter, due to the cancellation of a certain revenue contract discussed in Note 2—Basis of Presentation, Significant Accounting Policies and Recent Accounting Pronouncements — Contract Balances, $24.3 million was drawn on a $40.0 million letter of credit secured by the Company’s Prior Credit Facility. As of December 31, 2020 and 2019, the Company had standby letters of credit of $9.4 million and $49.5 million, respectively, which reduced the availability of the undrawn borrowing base. As of the date of this filing, and excluding any undrawn amounts under letters of credit, the available amount to be borrowed under the Prior Credit Facility was zero. As of the date of this filing, the Company had no borrowings outstanding under the Prior Credit Facility due to the Company’s emergence from bankruptcy described below.

Interest was paid on the Prior Credit Facility throughout 2020 because adequate protection was granted by the Bankruptcy Court to holders of the Prior Credit Facility in the form of interest payments. The adequate protection payments were classified as interest expense and not reduction of principal given that the debt was considered fully secured, and the Bankruptcy Court did not take any action to recharacterize the adequate protection payments as principal reduction. The weighted average interest rate for the Prior Credit Facility for the years ending December 31, 2020 and 2019 was 5.0% and 4.8%, respectively.

Upon emergence from bankruptcy on the Emergence Date, the Predecessor Credit Agreement was terminated and the holders of claims under the Predecessor Credit Agreement each received its ratable portion of the Predecessor Credit Agreement for its allowed claims. Also on this date all liens and security interests granted to secure such obligations were automatically terminated and are of no further force and effect.

2021 Senior Notes

In July 2016, the Company issued at par $550.0 million principal amount of 7.875% Senior Notes due July 15, 2021 (the “2021 Senior Notes” and the offering, the “2021 Senior Notes Offering”). The 2021 Senior Notes bore an annual interest rate of 7.875%. The interest on the 2021 Senior Notes was payable on January 15 and July 15 of each year commencing on January 15, 2017. The Company received net proceeds of approximately $537.2 million after deducting discounts and fees.

Concurrent with the 2026 Senior Notes Offering (as defined below), the Company commenced a cash tender offer to purchase any and all of its 2021 Senior Notes (the “Tender Offer”). On January 24, 2018, the Company received approximately $500.6 million aggregate principal amount of the 2021 Senior Notes which were validly tendered (and not validly withdrawn). As a result, on January 25, 2018 the Company made a cash payment of approximately $534.2 million, which includes principal of approximately $500.6 million, a make-whole premium of approximately $32.6 million and accrued and unpaid interest of approximately $1.0 million.

On February 17, 2018, the Company redeemed approximately $49.4 million aggregate principal amount of the 2021 Senior Notes that remained outstanding after the Tender Offer and made a cash payment of approximately $52.7 million to the remaining holders of the 2021 Senior Notes, which included a make-whole premium of $3.0 million and accrued and unpaid interest of approximately $0.3 million.

2024 Senior Notes

In August 2017, the Company issued at par $400.0 million principal amount of 7.375% Senior Notes due May 15, 2024 (the “2024 Senior Notes” and the offering, the “2024 Senior Notes Offering”). The 2024 Senior Notes bore an annual interest rate of 7.375%. The interest on the 2024 Senior Notes was payable on May 15 and November 15 of each year which commenced on November 15, 2017. The Company received net proceeds of approximately $392.6 million after deducting fees.

The Company’s 2024 Senior Notes were its senior unsecured obligations and ranked equally in right of payment with all of its other senior indebtedness and senior to any of its subordinated indebtedness. The Company’s 2024 Senior Notes were fully and unconditionally guaranteed on a senior unsecured basis by certain of the Company’s current subsidiaries and by certain future restricted subsidiaries that guarantees its indebtedness under a Prior Credit Facility (the “2024 Senior Notes Guarantors”). The 2024 Senior Notes were effectively subordinated to all of the Company’s secured indebtedness (including all borrowings and other obligations under its Prior Credit Facility) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated in right of payment to all existing and future indebtedness and other liabilities (including trade payables) of any of its future subsidiaries that did not guarantee the 2024 Senior Notes.

The 2024 Senior Notes also contained affirmative and negative covenants that, among other things, limited the Company’s and the 2024 Senior Notes Guarantors’ ability to make investments; declare or pay any dividend or make any other payment to holders of the Company’s or any of its 2024 Senior Notes Guarantors’ equity interests; repurchase or redeem any equity interests of the Company; repurchase or redeem subordinated indebtedness; incur additional indebtedness or issue preferred stock; create liens; sell assets; enter into agreements that restrict dividends or other payments by restricted subsidiaries; consolidate, merge or transfer all or substantially all of the assets of the Company; engage in transactions with the Company’s affiliates; engage in any business other than the oil and gas business; and create unrestricted subsidiaries. The indenture governing the 2024 Senior Notes also contained customary events of default. Upon the occurrence of events of default arising from certain events of bankruptcy or insolvency, the 2024 Senior Notes would have become due and payable immediately without any declaration or other act of the trustee or the holders of the 2024 Senior Notes. Upon the occurrence of certain other events of default, the trustee or the holders of at least 25% in aggregate principal amount of the then outstanding 2024 Senior Notes could declare all outstanding 2024 Senior Notes to be due and payable immediately.

The filing of the Chapter 11 Cases resulted in an event of default under and acceleration of the maturity of the Company’s 2024 Senior Notes.

On January 20, 2021, upon emergence from bankruptcy, the 2024 Senior Notes were cancelled. The holders of the 2024 Senior Notes received (i) their proportionate distribution of the New Common Stock and (ii) the right to participate in the Equity Rights Offering.

2026 Senior Notes

In January 2018, the Company issued at par $750.0 million principal amount of 5.625% Senior Notes due February 1, 2026 (the “2026 Senior Notes” and together with the 2024 Senior Notes, the “Senior Notes” and the offering, the offering of the 2026 Senior Notes, “2026 Senior Notes Offering”). The 2026 Senior Notes bore an annual interest rate of 5.625%. The interest on the 2026 Senior Notes was payable on February 1 and August 1 of each year commencing on August 1, 2018. The Company received net proceeds of approximately $737.9 million after deducting fees. The Company used $534.2 million of the net proceeds from the 2026 Senior Notes Offering to fund the tender offer for its 2021 Senior Notes, $52.7 million to redeem any 2021 Senior Notes not tendered and the remainder for general corporate purposes.

The Company’s 2026 Senior Notes were the Company’s senior unsecured obligations and ranked equally in right of payment with all of the Company’s other senior indebtedness and senior to any of the Company’s subordinated indebtedness. The Company’s 2026 Senior Notes were fully and unconditionally guaranteed on a senior unsecured basis by certain of the Company’s current subsidiaries and by certain future restricted subsidiaries that guarantee the Company’s indebtedness under a Prior Credit Facility (the “2026 Senior Notes Guarantors”). The 2026 Senior Notes were effectively subordinated to all of the Company’s secured indebtedness (including all borrowings and other obligations under its Prior Credit Facility) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated in right of payment to all existing and future indebtedness and other liabilities (including trade payables) of certain of the Company’s future restricted subsidiaries that do not guarantee the 2026 Senior Notes.

The 2026 Senior Notes also contained affirmative and negative covenants that, among other things, limited the Company’s and the 2026 Senior Notes Guarantors’ ability to make investments; declare or pay any dividend or make any other payment to holders of the Company’s or any of its 2026 Senior Notes Guarantors’ equity interests; repurchase or redeem any equity interests of the Company; repurchase or redeem subordinated indebtedness; incur additional indebtedness or issue preferred stock; create liens; sell assets; enter into agreements that restrict dividends or other payments by restricted subsidiaries; consolidate, merge or transfer all or substantially all of the assets of the Company; engage in transactions with the Company’s affiliates; engage in any business other than the oil and gas business; and create unrestricted subsidiaries. The indenture governing the 2026 Senior Notes also contained customary events of default. Upon the occurrence of events of default arising from certain events of bankruptcy or insolvency, the 2026 Senior Notes would have become due and payable immediately without any declaration or other act of the trustee or the holders of the 2026 Senior Notes. Upon the occurrence of certain other events of default, the trustee or the holders of at least 25% in aggregate principal amount of the then outstanding 2026 Senior Notes could declare all outstanding 2026 Senior Notes to be due and payable immediately.

The filing of the Chapter 11 Cases resulted in an event of default under and acceleration of the maturity of the Company’s 2026 Senior Notes.

On January 20, 2021, upon emergence from bankruptcy, the 2026 Senior Notes were cancelled. The holders of the 2026 Senior Notes received (i) their proportionate distribution of the New Common Stock and (ii) the right to participate in the Equity Rights Offering.

Debt Issuance Costs

Debt issuance costs include origination, legal and other fees incurred in connection with the Company’s Prior Credit Facility and Senior Notes. As of December 31, 2020 and 2019, the Company had debt issuance costs, net of accumulated amortization, of $0.1 million and $2.9 million, respectively, related to its Prior Credit Facility. As a result of bankruptcy, the Company wrote-off $13.5 million in unamortized debt issuance costs on the Senior Notes to reorganization items, net in the consolidated statements of operations. As of December 31, 2019, the Company had debt issuance costs net of accumulated amortization of $14.4 million related to its Senior Notes.. For the year ended December 31, 2020 and 2019, the Company recorded amortization expense related to the debt issuance costs of $3.7 million and $5.5 million, respectively.

Debt issuance costs of $1.7 million pertaining to the DIP Credit Facility were expensed to reorganization items, net during the year ended December 31, 2020.

Interest Incurred on Long-Term Debt

As discussed in Note 2—Basis of Presentation — Automatic Stay, during the proceedings of the Chapter 11 Cases, interest on the Senior Notes ceased being accrued and paid during 2020. However, interest was incurred, accrued and paid on the Prior Credit Facility due to the adequate protections obtained for this facility. Interest was incurred, accrued and paid on the DIP Credit Facility as it was obtained post-petition and approved by the Bankruptcy Court. For the years ended December 31, 2020 and 2019, the Company incurred interest expense on debt of $58.8 million and $91.5 million, respectively, and the Company capitalized interest expense on debt of $5.3 million and$7.2 million, respectively, for the years ended December 31, 2020 and 2019, which has been reflected in the Company’s consolidated financial statements.

Senior Note Repurchase Program

In January 2019, the Company’s board of directors (the “Board”) authorized a program to repurchase up to $100.0 million of the Company’s Senior Notes (the “Senior Notes Repurchase Program”). The Company’s Senior Notes Repurchase Program was subject to restrictions under the Prior Credit Facility and did not obligate it to acquire any specific nominal amount of Senior Notes. During 2020, the Company did not repurchase any Senior Notes. As a result of the Chapter 11 Cases, the authorization to repurchase Senior Notes is no longer applicable. During 2019, the Company repurchased 2026 Senior Notes with a nominal value of $49.8 million for $39.3 million in connection with the Senior Notes Repurchase Program. Interest expense for the year ended December 31, 2019 contained a $10.5 million gain on debt repurchase related to the Company’s Senior Notes Repurchase Program. The Senior Note Repurchase Program had no impact to interest expense for the years ended December 31, 2020.

Note 8—Commodity Derivative Instruments

The Company has entered into commodity derivative instruments, as described below. The Company has utilized swaps, put options and call options to reduce the effect of price changes on a portion of the Company’s future oil and natural gas production.

The Company combines swaps, purchased put options, purchased call options, sold put options and sold call options in order to achieve various hedging strategies. Some examples of the Company’s hedging strategies are collars which include purchased put options and sold call options, three-way collars which include purchased put options, sold put options and sold call options, and enhanced swaps, which include either sold put options or sold call options with the associated premiums rolled into an enhanced fixed price swap. The Company has historically relied on commodity derivative contracts to mitigate its exposure to lower commodity prices.

The objective of the Company’s use of commodity derivative instruments is to achieve more predictable cash flows in an environment of volatile oil and natural gas prices and to manage its exposure to commodity price risk. While the use of these commodity derivative instruments limits the downside risk of adverse price movements, such use may also limit the Company’s ability to benefit from favorable price movements. The Company may, from time to time, add incremental derivatives to hedge additional production, restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of the Company’s existing positions. The Company does not enter into derivative contracts for speculative purposes.

To reduce the impact of fluctuations in oil and natural gas prices on the Company’s revenues, the Company has periodically entered into commodity derivative contracts with respect to certain of its oil and natural gas production through various transactions that limit the downside of future prices received. Future transactions may include price swaps whereby the Company will receive a fixed price for its production and pay a variable market price to the contract counterparty. Additionally, the Company may enter into collars, whereby it receives the excess, if any, of the fixed floor over the floating rate or pay the excess, if any, of the floating rate over the fixed ceiling price. These hedging activities are intended to support oil and natural gas prices at targeted levels and to manage the Company’s exposure to oil and natural gas price fluctuations.

The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. The Company’s derivative contracts are currently with two counterparties, both of which are lenders under the Predecessor Credit Agreement and the DIP Credit Facility. The Company has netting arrangements with the counterparties that provide for the offset of payables against receivables from separate derivative arrangements with the counterparties in the event of contract termination. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement. There are no credit risk related contingent features or circumstances in which the features could be triggered in derivative instruments that are in a net liability position at the end of the reporting period.

Effect of Chapter 11 Cases

The commencement of the Chapter 11 Cases constituted a termination event with respect to the Company’s derivative instruments, which permitted the counterparties to such derivative instruments to terminate their outstanding hedges. Such termination events were not stayed under the Bankruptcy Code. During June 2020, certain of the lenders under the Predecessor Credit Agreement elected to terminate their International Swaps and Derivatives Association master agreements and outstanding hedges with the Company for aggregate settlement proceeds of $96.1 million. The proceeds from these terminations were applied to the outstanding borrowings under the Prior Credit Facility.

The Company’s open commodity derivative contracts as of December 31, 2020 are summarized below:

|  | 2021 |
NYMEX WTI Crude Swaps: |  |  |  |
Notional volume (Bbl) |  |  | 2,629,700 |
Weighted average fixed price ($/Bbl) |  | $ | 50.40 |

The table below sets forth the commodity derivatives gain (loss) for the years ended December 31, 2020 and 2019 (in thousands) included in the other income (expense) section of the consolidated statements of operations.

|  | For the Year Ended December 31, |
|  | 2020 |  |  | 2019 |
Commodity derivatives gain (loss) |  | $ | 164,968 |  |  | $ | (37,107 | )

Note 9—Asset Retirement Obligations

The Company follows accounting for asset retirement obligations in accordance with ASC 410, Asset Retirement and Environmental Obligations, which requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it was incurred if a reasonable estimate of fair value could be made. The Company’s asset retirement obligations primarily represent the estimated present value of the amounts expected to be incurred to plug, abandon and remediate producing and shut-in wells at the end of their productive lives in accordance with applicable local, state and federal laws, and applicable lease terms. The Company determines the estimated fair value of its asset retirement obligations by calculating the present value of estimated cash flows related to plugging and abandonment liabilities. The significant inputs used to calculate such liabilities include estimates of costs to be incurred; the Company’s credit adjusted discount rates, inflation rates and estimated dates of abandonment. The asset retirement liability is accreted to its present value each period and the capitalized asset retirement costs are depleted with proved oil and gas properties using the unit of production method.

The following table summarizes the activities of the Company’s asset retirement obligations for the periods indicated (in thousands):

|  | For the Year Ended |
|  | December 31, |
|  | 2020 |  |  | 2019 |
Balance beginning of period |  | $ | 95,908 |  |  | $ | 69,791 |
Liabilities incurred or acquired |  | $ | 333 |  |  | $ | 978 |
Liabilities settled |  | $ | (21,533 | ) |  | $ | (29,305 | )
Revisions in estimated cash flows (1) |  | $ | 13,617 |  |  | $ | 49,050 |
Accretion expense |  | $ | 6,444 |  |  | $ | 5,394 |
Balance end of period |  | $ | 94,769 |  |  | $ | 95,908 |

(1) Revisions in estimated cash flows during the year ended December 31, 2020 and 2019 were primarily due to changes in estimates of costs to be incurred to plug and abandon wells and changes in estimated dates of abandonment.

Note 10—Fair Value Measurements

ASC 820, Fair Value Measurement and Disclosure, establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows:

| • | Level 1: Quoted prices are available in active markets for identical assets or liabilities;

| • | Level 2: Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability;

| • | Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash flow models or valuations.

The financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. There were no transfers between levels during any periods presented below.

Commodity Derivative Instruments

The Company determines its estimate of the fair value of derivative instruments using a market based approach that takes into account several factors, including quoted market prices in active markets, implied market volatility factors, quotes from third parties, the credit rating of each counterparty, and the Company’s own credit rating. In consideration of counterparty credit risk, the Company assessed the possibility of whether each counterparty to the derivative would default by failing to make any contractually required payments. Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. Derivative instruments utilized by the Company consist of swaps, put options, and call options. The oil and natural gas derivative markets are highly active. Although the Company’s derivative instruments are valued using public indices, the instruments themselves are traded with third-party counterparties and are not openly traded on an exchange. As such, the Company has classified these instruments as Level 2.

Non-Recurring Fair Value Measurements

The Company applies the provisions of the fair value measurement standard on a non-recurring basis to its non-financial assets and liabilities, including proved property. These assets and liabilities are not measured at fair value on a recurring basis but are subject to fair value adjustments when facts and circumstances arise that indicate a need for remeasurement.

The Company utilizes fair value on a non-recurring basis to value its proved oil and gas properties when the results of the Company’s impairment evaluations indicate that the undiscounted future cash flows of an asset group do not exceed its carrying value. The Company uses an income approach analysis based on the net discounted future cash flows of proved property. The Company calculates the estimated fair values of its proved property oil and gas assets using a discounted future cash flow model. Significant inputs associated with the calculation of discounted future net cash flows include estimates of (i) recoverable reserves, (ii) future operating and development costs, (iii) future commodity prices, and (iv) a market-based weighted average cost of capital. The Company utilized the NYMEX strip pricing, adjusted for differentials, to value the reserves. These are classified as Level 3 fair value assumptions. At December 31, 2020, the Company’s estimate of commodity prices for purposes of determining discounted future cash flows ranged from a 2021 price of $48.29 per barrel of oil decreasing to a 2022 price of $46.76 per barrel of oil and decreasing further to a 2025 price of $44.84 per barrel of oil. Natural gas prices ranged from a 2021 price of $2.65 per Mcf decreasing to a 2025 price of $2.52 per Mcf. NGL prices ranged from a 2021 price of $13.45 per barrel decreasing to a 2025 price of $12.49 per barrel. These prices were then adjusted for location and quality differentials. The expected future net cash flows were discounted using a rate of 13.5 percent.

For the year ended December 31, 2020, the Company recognized $194.3 million in impairment expense on its oil and gas properties related to assets in its Core DJ Basin field as the fair value did not exceed the Company’s carrying amount attributable primarily to certain downward adjustments to the Company’s reserves due to expirations due to the SEC five year drilling rule caused by the change in business strategy to focus on cash flow rather than maximizing production and reserves growth. Additionally, downward revisions were due to altering the development plan to increase the spacing between wellbores, thus drilling fewer wells, as well as negative performance revisions. For the year ended December 31, 2019, the Company recognized $1.3 billion in impairment expense on its proved oil and gas properties related to assets in its Core DJ Basin field as the fair value did not exceed the Company’s carrying amount attributable primarily to certain downward adjustments to the Company’s reserves due to expirations due to the SEC five year drilling rule caused by the change in business strategy to focus on cash flow rather than maximizing production and reserves growth. For the years ended December 31, 2020 and 2019, the Company recognized $3.6 million and $14.5 million, respectively in impairment expense on its proved oil and gas properties related to assets in its northern field as the fair value did not exceed the Company’s carrying amount attributable primarily to certain downward adjustments to the Company’s economically recoverable proved oil and natural gas reserves.

The Company’s other non-recurring fair value measurements include the purchase price allocations for the fair value of assets and liabilities acquired through business combinations. The fair value of assets and liabilities acquired through business combinations is calculated using a discounted cash flow approach using Level 3 inputs. Cash flow estimates require forecasts and assumptions for many years into the future for a variety of factors, including risk-adjusted oil and gas reserves, commodity prices, development costs and operating costs, based on market participant assumptions. The fair value of assets or liabilities associated with purchase price allocations is on a non-recurring basis and is not measured in periods after initial recognition.

Note 11—Equity

Emergence from Chapter 11 Bankruptcy

On Emergence Date, the Company, pursuant to the terms of the Equity Rights Offering, issued New Common Stock in the Successor Company to various stakeholders as discussed in Note 1 — Business and Organization—Emergence from Chapter 11 Bankruptcy.

Warrant Agreements

On the Emergence Date, pursuant to the Plan, the Company entered into a warrant agreement with American Stock Transfer & Trust Company, LLC (“AST”) which provides for the Company’s issuance of up to an aggregate of 2,909,686 Tranche A Warrants (the “Tranche A Warrants”) to purchase New Common Stock to former holders of the Predecessor Common Stock and Predecessor Preferred Stock. The Company also entered into a warrant agreement with AST which provides for the Company’s issuance of up to an aggregate of 1,454,863 Tranche B Warrants (the “Tranche B Warrants” and, together with the Tranche A Warrants, the “New Warrants”) to purchase New Common Stock to former holders of the Predecessor Common Stock and Predecessor Preferred Stock. As of January 31, 2021, the Company had approximately 2.9 million and 1.5 million of Tranche A Warrants and Tranche B Warrants issued and outstanding, respectively.

Series A Preferred Stock

The holders of our Series A Preferred Stock (the “Series A Preferred Holders”) were entitled to receive a cash dividend of 5.875% per year, payable quarterly in arrears, and the Company had the ability to pay such quarterly dividends in kind at a dividend rate of 10% per year (decreased proportionately to the extent such quarterly dividends were partially paid in cash). The Company had paid the quarterly dividends in kind from the fourth quarter of 2019 until the filing of the Chapter 11 Cases. Because certain provisions within the RSA and the DIP Credit Agreement restricted the Company’s ability to declare a dividend, the Company has not made any dividend payments on the Series A Preferred Stock since the commencement of the Chapter 11 Cases. The Series A Preferred Stock was convertible into shares of our common stock at the election of the Series A Preferred Holders at a conversion ratio per share of Series A Preferred Stock of 61.9195. Until the three-year anniversary of the closing of the Company’s initial public offering (the “IPO,”), the Company could elect to convert the Series A Preferred Stock at a conversion ratio per share of Series A Preferred Stock of 61.9195, but only if the closing price of our common stock had traded at or above a certain premium to our initial offering price, such premium to decrease with time. On October 15, 2019, the three year anniversary had passed for the Series A Preferred Stock to convert into our common stock. Prior to the commencement of the Chapter 11 Cases, the Company could have redeemed the Series A Preferred Stock for the liquidation preference, which was $198.7 million on June 14, 2020. In certain situations, including a change of control, the Series A Preferred Stock could have been redeemed for cash in an amount equal to the greater of (i) 135% of the liquidation preference of the Series A Preferred Stock and (ii) a 17.5% annualized internal rate of return on the liquidation preference of the Series A Preferred Stock. The Series A Preferred Stock would have matured on October 15, 2021, at which time it would have been mandatorily redeemable for cash at the liquidation preference to the extent there were legally available funds to do so.

On the Emergence Date, pursuant to the Plan, each share of Series A Preferred Stock was canceled, released, and extinguished, and is of no further force or effect, and each holder of Series A Preferred Stock received, in full and final satisfaction, compromise, settlement, release, and discharge of, and in exchange for such Series A Preferred Stock, its pro rata share of (a) 1.5% of the New Common Stock, subject to certain dilution; (b) the right to purchase 1.5% of the New Common Stock in the backstopped equity offering to be issued pursuant to the terms of the Equity Rights Offering; (c) 50.0% of the Tranche A Warrants, and (d) 50.0% of the Tranche B Warrants to acquire an aggregate of 15.0% of the New Common Stock.

Elevation Preferred Units

In July 2019, Elevation sold 100,000 of Elevation Preferred Units at a price of $990 per unit to a third party (the “Purchaser”). The aggregate liquidation preference when the units were sold was $100.0 million. These Preferred Units represent the noncontrolling interest presented on the consolidated statements of operations and consolidated statements of changes in stockholders’ equity (deficit) and noncontrolling interest for periods ended on or prior to December 31, 2019. As part of the July 2018 transaction, the Company committed to Elevation that it would drill at least 297 qualifying wells in the acreage dedicated to Elevation by December 31, 2023, subject to reductions if Elevation does not invest the full amount of capital as initially anticipated. Pursuant to the Fourth Amendment to the Elevation Gathering Agreements between Elevation and Extraction, this drilling commitment would be eliminated, if and only if all Elevation Preferred Units have been redeemed in full or are otherwise no longer outstanding. Please see Note 15—Commitments and Contingencies — Elevation Gathering Agreements for further details on the settlement to reduce this drilling commitment.

Upon deconsolidation of Elevation Midstream, LLC as discussed in Note 1 — Business and Organization —Deconsolidation of Elevation Midstream, LLC, the $270.5 million Elevation preferred unit balance in the noncontrolling interest line item of the consolidated balance sheets as of March 31, 2020 was removed. The amount comprises the line item effects of deconsolidation of Elevation Midstream, LLC on the consolidated statements of changes in stockholders’ equity (deficit) and noncontrolling interest as of March 31, 2020.

During the twenty-eight months following the July 3, 2018 Preferred Unit closing date, Elevation is required to pay the Purchaser a quarterly commitment fee payable in cash or in kind of 1.0% per annum on any undrawn amounts of such additional $250.0 million commitment. For the year ended December 31, 2020, due to the deconsolidation of Elevation during the first quarter of 2020, the Company’s consolidated statements excluded all commitment fees paid-in-kind from the Preferred Unit commitment fees and dividends paid-in-kind line item in the consolidated statements of changes in stockholders’ equity (deficit) and noncontrolling interest. For the years ended December 31, 2020 and 2019, respectively, Elevation recognized $0.6 million and $3.1 million of commitment fees paid-in-kind.

The Elevation Preferred Units entitle the Purchaser to receive quarterly dividends at a rate of 8.0% per annum. The Dividend is currently payable solely in cash. For the year ended December 31, 2020, due to the deconsolidation of Elevation during the first quarter of 2020, the Company’s consolidated statements excluded all dividends paid-in-kind from the Preferred Unit commitment fees and dividends paid-in-kind line item in the consolidated statements of changes in stockholders’ equity (deficit) and noncontrolling interest. For the years ended December 31, 2020 and 2019, respectively, Elevation recognized $5.5 million and $16.9 million of dividends paid-in-kind.

Elevation Common Units

In May 2020, Elevation’s board of managers issued 1,530,000,000 common units at a price of $0.01 per unit to certain of Elevation’s members other than Extraction through the Capital Raise. The Capital Raise caused Extraction’s ownership of Elevation to be diluted to less than 0.01%. As a result of the Capital Raise, beginning in May 2020 Extraction began accounting for Elevation under the cost method of accounting. In December 2020, the Company reached a settlement with Elevation, which was approved by the Bankruptcy Court and as part of the settlement the Company relinquished all of its remaining ownership in Elevation.

Stock Repurchase Program

In November 2018, the Company announced that the Board had authorized a program to repurchase up to $100.0 million of the Company’s common stock (“Stock Repurchase Program”). On April 1, 2019, the Company announced the Board had authorized an extension and increase to the ongoing Stock Repurchase Program bringing the total amount authorized to $163.2 million (“Extended Stock Repurchase Program”). The Stock Repurchase Program and the Extended Stock Repurchase Program were both completed during 2019, bringing the total amount of common stock repurchased to 38.2 million shares for $163.2 million and a weighted average share price of $4.27. For the year ended December 31, 2019, the Company repurchased approximately 34.1 million shares of its common stock for $137.0 million. No common stock was repurchased during 2020.

Note 12—Income Taxes

The components of the income tax expense (benefit) were as follows (in thousands):

|  | For the Year Ended December 31, |
|  | 2020 |  |  | 2019 |
Current: |  |  |  |  |  |  |  |
Federal |  | $ | — |  |  | $ | — |
State, net of federal benefit |  |  | — |  |  |  | — |
Total current income tax expense (benefit) |  | $ | — |  |  | $ | — |
Deferred: |  |  |  |  |  |  |  |
Federal |  | $ | — |  |  | $ | (93,245 | )
State, net of federal expense (benefit) |  |  | — |  |  |  | (15,931 | )
Total deferred income tax expense (benefit) |  | $ | — |  |  | $ | (109,176 | )
Income tax expense (benefit) |  | $ | — |  |  | $ | (109,176 | )

Total income tax expense (benefit) differed from the amounts computed by applying the U.S. federal income tax rate to earnings (loss) before income taxes as a result of the following (in thousands):

|  | For the Year Ended December 31, |
|  | 2020 |  |  | 2019 |
Net income (loss) before income taxes |  | $ | (1,267,534 | ) |  | $ | (1,476,596 | )
Federal income taxes at statutory rate |  |  | (266,182 | ) |  |  | (310,085 | )
State income taxes, net of federal benefit |  |  | (41,582 | ) |  |  | (52,723 | )
Bankruptcy costs |  |  | 18,717 |  |  |  | — |
Deconsolidation of Elevation Midstream LLC |  |  | 2,448 |  |  |  | — |
Partnership income excluded |  |  | — |  |  |  | (3,558 | )
Nondeductible stock-based compensation |  |  | 3,216 |  |  |  | 9,436 |
Other |  |  | 2,568 |  |  |  | 1,626 |
Valuation allowance |  |  | 280,815 |  |  |  | 246,128 |
Income tax expense (benefit) |  |  | — |  |  |  | (109,176 | )
Net income (loss) |  | $ | (1,267,534 | ) |  | $ | (1,367,420 | )

As of December 31, 2020, the Company believes that it has no liability for uncertain tax positions. If the Company were to determine there are any uncertain tax positions, the Company would recognize the liability and related interest and penalties within income tax expense. As of December 31, 2020, the Company had no provision for interest or penalties related to uncertain tax positions.

Effect of Chapter 11 Cases and Emergence from Chapter 11 Cases

On July 13, 2020 the Bankruptcy Court entered a final order approving certain procedures (including notice requirements) that certain shareholders and potential shareholders were required to comply with during the pendency of the Chapter 11 Cases regarding transfers of, or declarations of worthlessness with respect to, the Company’s Predecessor Common Stock and Predecessor Preferred Stock, as well as certain obligations with respect to notifying the Company with respect to current share ownership, each of which were intended to preserve the Company’s ability to use its NOLs to offset possible future U.S. taxable income by reducing the likelihood of an ownership change under Section 382 of the Code during the pendency of the Chapter 11 Cases.

The consummation of the Plan on the Emergence Date resulted in an “ownership change” of the Company under Section 382 of the Code. Absent an applicable exception, if a corporation undergoes an “ownership change,” the amount of its pre-ownership change net operating losses that may be utilized to offset future taxable income generally will be subject to an annual limitation equal to the value of its stock immediately prior to the ownership change multiplied by the long-term tax exempt rate, plus an additional amount calculated based on certain “built in gains” in its assets that may be deemed to be realized within a 5-year period following any ownership change. This limitation, in the case of the ownership change that occurred as a result of the consummation of the Plan, will be subject to additional rules under Sections 382(l)(5) or (l)(6) of the Code, depending upon whether we are eligible for the application of Section 382(l)(5) of the Code and, if so eligible, whether we affirmatively elect not to apply Section 382(l)(5) of the Code. As a result of such limitation, the Company’s ability to utilize any NOLs or other tax attributes that are not eliminated as a result of cancellation of indebtedness income arising from the consummation of the Plan may be materially limited in the future.

The CARES Act provides relief to corporate taxpayers by permitting a five year carryback of 2018-2020 NOLs, removing the 80% limitation on the carryback of those NOLs, increasing the Section 163(j) 30% limitation on interest expense deductibility to 50% of adjusted taxable income for 2019 and 2020 as well as allowing 2019 adjusted taxable income to be utilized for 2020 limitation purposes, and accelerating refunds for minimum tax credit carryforwards, along with a few other provisions.

Note 13—Stock-Based Compensation

2021 Long Term Incentive Plan

On January 20, 2021, as part of the emergence from bankruptcy, the Board adopted the 2021 Long Term Incentive Plan (the “2021 LTIP”) with a share reserve equal to 3,038,657 shares of New Common Stock. The 2021 LTIP provides for the grant of restricted stock units, restricted stock awards, stock options, stock appreciation rights, performance awards and cash awards to the Company’s employees and non-employee board directors. At emergence the Company granted awards under the 2021 LTIP to its directors, officers and employees, including restricted stock units and performance stock units.

2016 Long Term Incentive Plan

In October 2016, the Company’s Board adopted the Extraction Oil & Gas, Inc. 2016 Long Term Incentive Plan (“2016 LTIP”), pursuant to which employees, consultants, and directors of the Company and its affiliates performing services for the Company were eligible to receive awards. The 2016 LTIP provided for the grant of stock options, stock appreciation rights, restricted stock, restricted stock units, bonus stock, dividend equivalents, other stock-based awards, substitute awards, annual incentive awards, and performance awards intended to align the interests of participants with those of stockholders. In May 2019, the Company’s stockholders approved the amendment and restatement of the 2016 LTIP. The amended and restated 2016 Long Term Incentive Plan provided a total reserve of 32.2 million shares of Predecessor Common Stock for issuance pursuant to awards under the 2016 LTIP. Extraction granted awards under the 2016 LTIP to certain directors, officers and employees, including stock options, restricted stock units, performance stock awards, performance stock units, performance cash awards and cash awards. Effective January 20, 2021, as part of the emergence from bankruptcy, the 2016 LTIP was terminated and no longer in effect and all outstanding awards were cancelled.

Restricted Stock Units

Restricted stock units granted under the 2016 LTIP (“RSUs”) generally vested over either a one or three-year service period, with 100% vesting in year one or 25%, 25% and 50% of the units vesting in year one, two and three, respectively. Grant date fair value was determined based on the value of Extraction’s common stock pursuant to the terms of the 2016 LTIP. The Company assumed a forfeiture rate of zero as part of the grant date estimate of compensation cost.

The Company recorded $4.7 million and $23.8 million of stock-based compensation costs related to RSUs for the years ended December 31, 2020 and 2019, respectively. These costs were included in the consolidated statements of operations within the general and administrative expenses line item. As of December 31, 2020, there was $2.9 million of total unrecognized compensation cost related to the unvested RSUs granted to certain directors, officers and employees that is expected to be recognized over a weighted average period of 1.0 year.

The following table summarizes the RSU activity from January 1, 2019 through December 31, 2020 and provides information for RSUs outstanding at the dates indicated.

|  |  |  |  | Weighted Average |
|  | Number of |  |  | Grant Date |
|  | Shares |  |  | Fair Value |
Non-vested RSUs at January 1, 2019 |  |  | 3,102,335 |  |  | $ | 16.91 |
Granted |  |  | 1,905,918 |  |  | $ | 4.75 |
Forfeited |  |  | (469,035 | ) |  | $ | 10.54 |
Vested |  |  | (1,903,453 | ) |  | $ | 18.20 |
Non-vested RSUs at December 31, 2019 |  |  | 2,635,765 |  |  | $ | 8.32 |
Granted |  |  | 1,409,765 |  |  | $ | 0.75 |
Forfeited |  |  | (1,852,249 | ) |  | $ | 3.00 |
Vested |  |  | (1,007,930 | ) |  | $ | 9.09 |
Non-vested RSUs at December 31, 2020 |  |  | 1,185,351 |  |  | $ | 6.99 |

Performance Stock Awards

The Company granted performance stock awards (“PSAs”) to certain executives under the 2016 LTIP in October 2017, March 2018, April 2019 and March 2020. The number of shares of the Company’s common stock that may be issued to settle these various PSAs ranges from zero to two times the number of PSAs awarded. PSA’s that settle in cash are presented as liability awards. Generally, the shares issued for PSAs are determined based on the satisfaction of a time-based vesting schedule and a weighting of one or more of the following: (i) absolute total stockholder return (“ATSR”), (ii) relative total stockholder return (“RTSR”), as compared to the Company’s peer group and (iii) cash return on capital invested (“CROCI”) or return on invested capital (“ROIC”) measured over a three-year period and vest in their entirety at the end of the three-year measurement period. Any PSAs that have not vested at the end of the applicable measurement period are forfeited. The vesting criterion that is associated with the RTSR is based on a comparison of the Company’s total shareholder return for the measurement period compared to that of a group of peer companies for the same measurement period. As the ATSR and RTSR vesting criteria are linked to the Company’s share price, they each are considered a market condition for purposes of calculating the grant-date fair value of the awards. The vesting criterion that is associated with the CROCI and ROIC are considered a performance condition for purposes of calculating the grant-date fair value of the awards.

The fair value of the PSAs was measured at the grant date with a stochastic process method using a Monte Carlo simulation. Significant assumptions used in this simulation include the Company’s expected volatility, risk-free interest rate based on U.S. Treasury yield curve rates with maturities consistent with the measurement period as well as the volatilities for each of the Company’s peers.

The assumptions used in valuing the PSAs granted were as follows:

|  | For the Years Ended |
|  | December 31, 2020 |  |  | December 31, 2019 |
Risk free rates |  |  | 0.6 | % |  |  | 2.3 | %
Dividend yield |  |  | — |  |  |  | — |
Expected volatility |  |  | 83.7 | % |  |  | 58.5 | %

The Company recorded $1.7 million and $7.3 million of stock-based compensation costs related to PSAs for the years ended December 31, 2020 and 2019, respectively. These costs were included in the consolidated statements of operations within the general and administrative expenses line item. As of December 31, 2020, there was $0.9 million of total unrecognized compensation cost related to the unvested PSAs granted to certain executives that is expected to be recognized over a weighted-average period of 1.1 years.

The following table summarizes the PSA activity from January 1, 2019 through December 31, 2020 and provides information for PSAs outstanding at the dates indicated.

|  |  |  |  | Weighted Average |
|  | Number of |  |  | Grant Date |
|  | Shares(1) |  |  | Fair Value |
Non-vested PSAs at January 1, 2019 |  |  | 2,794,083 |  |  | $ | 9.00 |
Granted |  |  | 1,224,696 |  |  | $ | 5.63 |
Forfeited |  |  | (418,229 | ) |  | $ | 8.17 |
Cancelled |  |  | (737,360 | ) |  | $ | 8.85 |
Vested |  |  | — |  |  | $ | — |
Non-vested PSAs at December 31, 2019 |  |  | 2,863,190 |  |  | $ | 7.72 |
Granted |  |  | 5,952,700 |  |  | $ | 0.29 |
Forfeited (2) |  |  | (5,881,200 | ) |  | $ | 0.29 |
Cancelled |  |  | (1,738,411 | ) |  | $ | 9.06 |
Vested |  |  | — |  |  | $ | — |
Non-vested PSAs at December 31, 2020 |  |  | 1,196,279 |  |  | $ | 5.32 |

| (1) | The number of awards assumes that the associated maximum vesting condition is met at the target amount. The final number of shares of the Company’s common stock issued may vary depending on the performance multiplier, which ranges from zero to one for the 2017 and 2018 grants and ranges from zero to two for the 2019 and 2020 grants, depending on the level of satisfaction of the vesting condition.

| (2) | The Company approved retention agreements on June 12, 2020 with certain executives and senior managers. These retention agreements, are subject to repayment upon a resignation without “good reason” or termination of employment for “cause” before specified dates and events. As a condition to participating in the revised compensation program, the equity compensation awards granted in 2020 were forfeited.

Stock Options

Expense on the stock options is recognized on a straight-line basis over the service period of the award less awards forfeited. The fair value of the stock options was measured at the grant date using the Black-Scholes valuation model. The Company utilized the “simplified” method to estimate the expected term of the stock options granted as at the time there was limited historical exercise data available in estimating the expected term of the stock options. Expected volatility is based on the volatility of the historical stock prices of the Company’s peer group. The risk-free rates are based on the yields of U.S. Treasury instruments with comparable terms. A dividend yield and forfeiture rate of zero were assumed. Stock options granted under the 2016 LTIP vest ratably over three years and are exercisable immediately upon vesting through the tenth anniversary of the grant date. To fulfill options exercised, the Company will issue new shares.

The Company recorded no stock-based compensation costs related to stock options for the year ended December 31, 2020. The Company recorded $12.1 million of stock-based compensation costs related to the stock options for the year ended December 31, 2019. These costs were included in the consolidated statements of operations within the general and administrative expenses line item. As of December 31, 2020, there are no remaining unrecognized compensation costs related to the stock options granted to certain executives.

No stock options were granted for the years ended December 31, 2020 and 2019.

The following table summarizes the stock option activity from January 1, 2019 through December 31, 2020 and provides information for stock options outstanding at the dates indicated.

|  | Number of Shares |  |  | Weighted Average Exercise Price |  |  | Aggregate Intrinsic Value (in thousands) |
Non-vested Stock Options at January 1, 2019 |  |  | 1,748,148 |  |  | $ | 18.50 |  |  | $ | — |
Granted |  |  | — |  |  | $ | — |  |  | $ | — |
Forfeited |  |  | — |  |  | $ | — |  |  | $ | — |
Vested |  |  | (1,748,148 | ) |  | $ | 18.50 |  |  | $ | — |
Non-vested Stock Options at December 31, 2019 |  |  | — |  |  | $ | — |  |  | $ | — |
Granted |  |  | — |  |  | $ | — |  |  | $ | — |
Forfeited |  |  | — |  |  | $ | — |  |  | $ | — |
Vested |  |  | — |  |  | $ | — |  |  | $ | — |
Non-vested Stock Options at December 31, 2020 |  |  | — |  |  | $ | — |  |  | $ | — |

The following table summarizes information about outstanding and exercisable stock options as of December 31, 2020.

| Outstanding and Exercisable Options |
|  |  |  | Weighted-Average |  |  | Weighted-Average |  |  |  | Aggregate Intrinsic Value |
| Options |  |  | Remaining Contractual Life |  |  | Exercise Price |  |  |  | (thousands) |
| 4,500,000 |  |  | 5.9 years |  | $ | 19.00 |  |  | $ | — |
| 744,428 |  |  | 6.8 years |  | $ | 15.53 |  |  | $ | — |
| 5,244,428 |  |  | 6.0 years |  | $ | 18.50 |  |  | $ | — |

Incentive Restricted Stock Units

Officers of the Company contributed 2.7 million shares of common stock to Extraction Employee Incentive, LLC (“Employee Incentive”), which is owned solely by certain officers of the Company. Employee Incentive issued restricted stock units (“Incentive RSUs”) to certain employees. Incentive RSUs vested over a three-year service period, with 25%, 25% and 50% of the units vesting in year one, two and three, respectively. On July 17, 2017, the partners of Employee Incentive amended the vesting schedule in which 25% vested immediately and the remaining Incentive RSUs vest 25%, 25% and 25% each six months thereafter, over the remaining 18 month service period. Grant date fair value was determined based on the value of the Company’s common stock on the date of issuance. The Company assumed a forfeiture rate of zero as part of the grant date estimate of compensation cost.

The Company recorded no stock-based compensation costs related to Incentive RSUs for the year ended December 31, 2020. The Company recorded $0.8 million of stock-based compensation costs related to Incentive RSUs for the year ended December 31, 2019. These costs were included in the consolidated statements of operations within the general and administrative expenses line item. As of December 31, 2020, there are no remaining unrecognized compensation costs related to the Incentive RSUs granted to certain employees.

The following table summarizes the Incentive RSU activity from January 1, 2019 through December 31, 2020 and provides information for Incentive RSUs outstanding at the dates indicated.

|  |  |  |  | Weighted Average |
|  | Number of |  |  | Grant Date |
|  | Shares |  |  | Fair Value |
Non-vested Incentive RSUs at January 1, 2019 |  |  | 476,000 |  |  | $ | 20.45 |
Granted |  |  | — |  |  | $ | — |
Forfeited |  |  | — |  |  | $ | — |
Vested |  |  | (476,000 | ) |  | $ | 20.45 |
Non-vested Incentive RSUs at December 31, 2019 |  |  | — |  |  | $ | — |
Granted |  |  | — |  |  | $ | — |
Forfeited |  |  | — |  |  | $ | — |
Vested |  |  | — |  |  | $ | — |
Non-vested Incentive RSUs at December 31, 2020 |  |  | — |  |  | $ | — |

Note 14—Earnings (Loss) Per Share

Basic earnings per share (“EPS”) includes no dilution and is computed by dividing net income (loss) available to common shareholders by the weighted-average number of shares outstanding during the period. Diluted EPS reflects the potential dilution of securities that could share in the earnings available to common shareholders of the Company. The Company uses the “if-converted” method to determine potential dilutive effects of Series A Preferred Stock and the treasury method to determine the potential dilutive effects of outstanding restricted stock awards and stock options.

The components of basic and diluted EPS were as follows (in thousands, except per share data):

|  | For the Year Ended December 31, |
|  | 2020 |  |  | 2019 |
Basic and Diluted Income (Loss) per Share |  |  |  |  |  |  |  |
Net income (loss) |  | $ | (1,267,534 | ) |  | $ | (1,367,420 | )
Less: Noncontrolling interest |  |  | (6,160 | ) |  |  | (19,992 | )
Less: Adjustment to reflect Series A Preferred Stock dividend |  |  | (8,749 | ) |  |  | (12,796 | )
Less: Adjustment to reflect accretion of Series A Preferred Stock discount |  |  | (7,366 | ) |  |  | (6,640 | )
Net income (loss) available to common shareholders, basic and diluted |  | $ | (1,289,809 | ) |  | $ | (1,406,848 | )
Weighted Average Common Shares Outstanding (1) (2) |  |  |  |  |  |  |  |
Basic and diluted |  |  | 138,149 |  |  |  | 151,481 |
Net Income (Loss) Allocated to Common Shareholders per Common Share |  |  |  |  |  |  |  |
Basic and diluted |  | $ | (9.34 | ) |  | $ | (9.29 | )

| (1) | For the year ended December 31, 2020, 1,185,351 potentially dilutive shares associated with restricted stock awards outstanding were not included in the calculation above, as they had an anti-dilutive effect on EPS. Additionally, 5,244,428 common shares for stock options were excluded as they were out of the money and 11,472,445 common shares associated with the assumed conversion of Series A Preferred Stock were also excluded.

| (2) | For the year ended December 31, 2019, 2,635,765 potentially dilutive shares associated with restricted stock awards outstanding were not included in the calculation above, as they had an anti-dilutive effect on EPS. Additionally, 5,244,428 common shares for stock options were excluded as they were out of the money and 11,472,445 common shares associated with the assumed conversion of Series A Preferred Stock were also excluded.

Note 15—Commitments and Contingencies

Chapter 11 Cases

On June 14, 2020, the Company filed the Chapter 11 Cases seeking relief under the Bankruptcy Code. The Company continues to operate its business and manage its properties in the ordinary course of business pursuant to the applicable provisions of the Bankruptcy Code. In addition, commencement of the Chapter 11 Cases automatically stayed many of the proceedings and actions against the Company (other than regulatory enforcement matters), including those noted below. Please refer to Note 1 — Business and Organization for more information on the Chapter 11 Cases.

General

As is customary in the oil and gas industry, the Company may at times have commitments in place to reserve or earn certain acreage positions or wells. If the Company does not meet such commitments, the acreage positions or wells may be lost, or the Company may be required to pay damages if certain performance conditions are not met.

Leases

The Company has entered into operating leases for certain office facilities, compressors and office equipment. As of December 31, 2020, the Company leased one office space under an operating lease agreement that expires on November 30, 2021. Rent expense was $3.1 million and $3.5 million for the years ended December 31, 2020 and 2019, respectively. On January 1, 2019, the Company adopted ASC Topic 842, Leases, using the modified retrospective approach. Refer to Note 6 — Leases for additional information.

In connection with the Chapter 11 Cases, the Company filed a motion to reject its drilling rig contracts effective June 14, 2020. For one of the contracts, the rejection resulted in the removal of the lease liability and net right-of-use asset in the amount of $6.7 million. The Company amended its office lease contract effective December 7, 2020. The amendment resulted in the removal of the lease liability and the net right-of-use asset in the amount of $13.2 million and $9.4 million, respectively.

Maturities of operating lease liabilities associated with right-of-use assets including imputed interest but excluding rejected contracts were as follows (in thousands):

|  | As of December 31, 2020 |  |  |  |  | As of December 31, 2019 |
|  |  |  |  |  | 2020 |  |  | 19,040 |
2021 |  |  | 4,549 |  |  | 2021 |  |  | 5,247 |
2022 |  |  | 3,176 |  |  | 2022 |  |  | 2,211 |
2023 |  |  | 1,139 |  |  | 2023 |  |  | 2,246 |
2024 |  |  | 199 |  |  | 2024 |  |  | 2,301 |
Thereafter |  |  | — |  |  | Thereafter |  |  | 8,273 |
Total lease payments (1) |  |  | 9,063 |  |  | Total lease payments (1) |  |  | 39,318 |
Less imputed interest |  |  | (427 | ) |  | Less imputed interest |  |  | (4,735 | )
Present value of lease liabilities |  | $ | 8,636 |  |  | Present value of lease liabilities |  | $ | 34,583 |

(1) Calculated using the estimated interest rate for each lease.

Drilling Rigs

As of December 31, 2020, the Company was not subject to commitments on any drilling rigs. As part of its case in chapter 11, the Company filed a motion to reject its drilling rig contracts. As such, the Company recorded $6.7 million in reorganization items, net on the consolidated statements of operations. During the first quarter of 2021, the Company agreed to have a drilling rig on a 30-day rolling term drill various pads during 2021.

Delivery Commitments

During the third and fourth quarters of 2020, the majority of the Company’s material midstream contracts were renegotiated and/or rejected by the Bankruptcy Court as part of the Chapter 11 Cases. As a result of these rejections or renegotiated contracts, the Company eliminated the majority of its minimum volume commitments as described below and accrued $550.5 million in reorganization items, net on the consolidated statements of operations for the year ended December 31, 2020.

The Company was subject to a firm transportation agreement that commenced in November 2016 and had a ten-year term with a monthly minimum delivery commitment of 45,000 Bbl/d in year one, 55,800 Bbl/d in year two, 61,800 Bbl/d in years three through seven and 58,000 Bbl/d in years eight through ten. Until July 2020, these commitments were obligations of the Company’s third-party oil marketer, which reverted back to the Company when the associated oil marketing contract terminated in June 2020. After termination of the aforementioned contract with its third-party oil marketer, the Company had a long-term crude oil delivery commitment agreement that commenced on July 1, 2020. Before the Bankruptcy Court rejected this contract, the Company’s long-term crude oil delivery commitment had a monthly minimum delivery commitment of 61,800 Bbl/d through October 2023 and then would have reduced to 58,000 Bbl/d through October 2026. The Company was required to pay a shortfall fee for any volume deficiencies under these commitments. On November 2, 2020, the Bankruptcy Court ruled in favor of the Company rejecting this contract with an effective date as of June 14, 2020, and, therefore, the Company has no remaining minimum volume commitments under this transportation contract. On December 19, 2020, the Company and the counterparty entered into a settlement agreement and also entered into a new supply agreement that has no minimum volume commitments.

The Company had two long-term crude oil gathering commitments with two former unconsolidated subsidiaries in which the Company had a de minimis minority ownership interest. Please see Note 1 - Business and Organization — Deconsolidation of Elevation Midstream, LLC for further information. The first agreement commenced in November 2016 and had a term of ten years with a minimum volume commitment of an average of 9,167 Bbl/d in year one, 17,967 Bbl/d in year two, 18,800 Bbl/d for years three through five and 10,000 Bbl/d for years six through ten. The second agreement commenced in October 2019 and had a term of ten years for an average of 3,200 Bbl/d in year one, 8,000 Bbl/d in year two, 14,000 Bbl/d in year three, 16,000 Bbl/d in years four through eight, 12,000 Bbl/d in year nine and 10,000 Bbl/d in year ten. The Company would have been required to pay a shortfall fee for any volume deficiencies under these commitments. On November 2, 2020, the Bankruptcy Court ruled in favor of the Company rejecting both of these crude oil gathering contracts with an effective date of June 14, 2020, and, therefore, the Company has no remaining minimum volume commitments under these contracts. On January 4, 2021, the Company and the counterparty entered into a settlement agreement and subsequently entered into two new transportation service agreements that have no minimum volume commitments.

In February 2019, the Company entered into a long-term gas gathering and processing agreement with a third-party midstream providers. The agreement commenced in November 2019 and had a term of twenty years with a minimum volume commitment of 251 Bcf to be delivered within the first seven years. The annual commitments over seven years were to be delivered on an average 85,000 Mcf/d in year one, 125,000 Mcf/d in year two, 140,000 Mcf/d in year three, 118,000 Mcf/d in year four, 98,000 Mcf/d in year five, 70,000 Mcf/d in year six and 52,000 Mcf/d in year seven. On January 20, 2021, the Company and the counterparty entered into a settlement agreement and amended its three long-term gas gathering and processing agreements and one oil gathering agreement with the same party. As part of the settlement and amended agreements, all prior minimum volume commitments were relieved. There are no minimum volume commitments in the amended agreements.

The Company entered into another long-term gas gathering and processing agreement with a different third party midstream provider in February 2019. This agreement commenced in January 2020 and has a term of ten years with an annual minimum volume commitment of 13.0 Bcf. This agreement also includes a commitment to sell take-in-kind NGLs from other processing agreements of 4,000 Bbl/d in year one and 7,500 Bbl/d in years two through seven with the ability to roll up to a 10% shortfall in a given month to the subsequent month. On December 23, 2020, the Company and the counterparty entered into a settlement and amended the agreement. As part of the settlement and amended agreement, there were no changes made to the minimum volume commitments.

In collaboration with several other producers and a midstream provider, on December 15, 2016 and August 7, 2017, the Company agreed to participate in expansions of natural gas gathering and processing capacity in the DJ Basin. The plan included two new processing plants as well as the expansion of related gathering systems. The first plant commenced operations in August 2018 and the second plant commenced operations in July 2019. The Company’s share of these commitments will require an incremental 51.5 and 20.6 MMcf per day, respectively, over a baseline volume of 65 MMcf per day to be delivered after the plants’ in-service dates for a period of seven years thereafter. The Company may be required to pay a shortfall fee for any incremental volume deficiencies under these commitments. These contractual obligations can be reduced by the Company’s proportionate share of the collective volumes delivered to the plants by other third-party incremental volumes available to the midstream provider at the new facilities that are in excess of the total commitments. The Company is also required for the first three years of each contract to guarantee a certain target profit margin on these volumes sold.

In July 2019, the Company entered into three long-term contracts to supply 125,000 dekatherms of residue gas per day for five years to a transportation company. On November 24, 2020, the Bankruptcy Court ruled in favor of the Company rejecting this contract with an effective date as of December 10, 2020, and, therefore, the Company has no remaining minimum volume commitments under this transportation contract. The Company had previously posted a letter of credit for this agreement in the amount of $8.7 million. On February 8, 2021, the transportation company drew the full amount of the letter of credit on the Company’s RBL Credit Facility, and this drawing was converted into a borrowing under the RBL Credit Facility.

Elevation Gathering Agreements

In July 2018, the Company entered into three long-term gathering agreements (the “Elevation Gathering Agreements”) for gas, crude oil and produced water with Elevation. Under the agreements, the Company agreed to drill 100 wells in Broomfield and 325 wells in Hawkeye by December 31, 2023 if both facilities are to be built, subject to adjustments if less capital is spent. If the Company were to fail to complete the wells by the applicable deadline, then it would be in breach of the agreement and Elevation could attempt to assert damages against Extraction and its affiliates. During the first quarter of 2020, Elevation postponed indefinitely further development of gathering systems and facilities that were to be constructed to service the Company’s acreage in Hawkeye and another project in the Southwest Wattenberg area. Due to the decision to not complete the Hawkeye facilities and based on the amount of capital invested, Elevation had asserted that the drilling commitment now consists of 297 wells in the Broomfield area of operations with a deadline of December 31, 2022. As discussed below, in December 2020 this drilling commitment was further reduced to 106 wells.

In April 2019, the Elevation Gathering Agreements were amended to provide for, among other amendments, the inclusion of additional gathering facilities that would produce into Elevation’s Badger facility.

In December 2019, the Elevation Gathering Agreements were further amended to provide Elevation additional connection fees that are consistent with market terms (the “Connect Fees”). In the fourth quarter of 2019, the Company incurred and paid $19.5 million for Connect Fees pursuant to the Elevation Gathering Agreements, and in the first quarter of 2020 the Company incurred and paid $23.5 million. The Company did not incur additional Connect Fees for the year ended December 31, 2020.

In April 2020, pursuant to the amendment to the Elevation Gathering Agreements made in April 2019 discussed above, Elevation asserted that the additional gathering facilities that were required to be completed by April 1, 2020 were not built thus Extraction must make a payment to Elevation in the amount of 135% of all costs incurred by Elevation as of such date for the development and construction of such additional gathering facilities. On April 2, 2020, Elevation demanded payment of $46.8 million due to an alleged breach in contract stemming from a purported failure to complete the pipeline extensions connecting certain wells to the Badger central gathering facility prior to April 1, 2020. The Company recorded the amount in other operating expenses on the condensed consolidated statements of operations for the year ended December 31, 2020.

On December 15, 2020, the Company and Elevation reached an agreement regarding amendments to the gathering agreements and the settlement of all outstanding claims. As part of the settlement, the Company will pay Elevation $38.4 million in cash over 24 months, and Elevation submitted an unsecured claim of $80.0 million with the Bankruptcy Court. The agreement released certain areas from future dedication, provided a reduction in certain gathering fees, a reduction in the number of wells subject to the drilling commitment, and an extended term in order to satisfy the remaining drilling commitment. The Company also relinquished the nominal common interest ownership it had in Elevation. The Company previously accrued $46.8 million and $4.2 million of accrued interest related to the aforementioned alleged breach in contract. During the third quarter of 2020, the Company accrued an additional $68.7 million in reorganization items, net on the consolidated statements of operations.

General

The Company is subject to contingent liabilities with respect to existing or potential claims, lawsuits, and other proceedings, including those involving environmental, tax, and other matters, certain of which are discussed more specifically below. The Company accrues liabilities when it is probable that future costs will be incurred and such costs can be reasonably estimated. Such accruals are based on developments to date and the Company’s estimates of the outcomes of these matters and its experience in contesting, litigating, and settling other matters. As the scope of the liabilities becomes better defined, there will be changes in the estimates of future costs, which management currently believes will not have a material effect on the Company’s financial position, results of operations, or cash flows.

As is customary in the oil and gas industry, the Company may at times have commitments in place to reserve or earn certain acreage positions or wells. If the Company does not meet such commitments, the acreage positions or wells may be lost or the Company may be required to pay damages if certain performance conditions are not met.

Litigation and Legal Items

The Company is involved in various legal proceedings and reviews the status of these proceedings on an ongoing basis and, from time to time, may settle or otherwise resolve these matters on terms and conditions that management believes are in the Company’s best interests. The Company has provided the necessary estimated accruals where deemed appropriate for litigation and legal related items that are ongoing and not yet concluded. Although the results cannot be known with certainty, the Company currently believes that the ultimate results of such proceedings will not have a material adverse effect on our business, financial position, results of operations or liquidity.

Environmental. Due to the nature of the oil and natural gas industry, the Company is exposed to environmental risks. The Company has various policies and procedures to minimize and mitigate the risks from environmental contamination or with respect to environmental compliance issues. Liabilities are recorded when environmental damages resulting from past events are probable and the costs can be reasonably estimated. Except as discussed herein, the Company is not aware of any material environmental claims existing as of December 31, 2020 which have not been provided for or would otherwise have a material impact on the Company’s financial statements; however, there can be no assurance that current regulatory requirements will not change or that unknown potential past non-compliance with environmental laws, compliance matters or other environmental liabilities will not be discovered on our properties. The liability ultimately incurred with respect to a matter may exceed the related accrual.

COGCC Notices of Alleged Violations (“NOAVs”). The Company has received NOAVs from the Colorado Oil and Gas Conservation Commission (the “COGCC”) for alleged compliance violations that the Company has responded to. The Company does not believe penalties that could result from these NOAVs will have a material effect on its business, financial condition, results of operations or liquidity, but Extraction is in negotiations to settle all of its outstanding NOAVs with the COGCC, and the ultimate settlement amount is expected to exceed $600,000.

Note 16—Related Party Transactions

Elevation Midstream, LLC

As discussed in Note 15 — Commitments and Contingencies — Elevation Gathering Agreements, on April 2, 2020, Elevation demanded payment of $46.8 million due to an alleged breach in contract stemming from a purported failure to complete the pipeline extensions connecting certain wells to the Badger central gathering facility prior to April 1, 2020. In December 2020, the Company and Elevation reached an agreement regarding amendments to the gathering agreements and the settlement of outstanding claims. As part of the settlement, the Company will pay Elevation $38.4 million in cash over 24 months, and Elevation submitted an unsecured claim of $80.0 million with the Bankruptcy Court. The agreement released certain areas from future dedication, provided a reduction in certain gathering fees, a reduction in the number of wells subject to the drilling commitment, and an extended term in order to satisfy the drilling commitment. The Company also relinquished the nominal common interest ownership it had in Elevation. The Company previously accrued $46.8 million and $4.2 million of accrued interest related to the aforementioned alleged breach in contract. During the third quarter of 2020, the Company accrued an additional $68.7 million in reorganization items, net on the consolidated statements of operations.

2024 Senior Notes

Several 5% stockholders of the Company were also holders of the 2024 Senior Notes. As of the initial issuance in August 2017 of the $400.0 million principal amount on the 2024 Senior Notes, such stockholders held $54.9 million.

2026 Senior Notes

Several 5% stockholders of the Company were also holders of the 2026 Senior Notes. As of the initial issuance in January 2018 of the $750.0 million principal amount on the 2026 Senior Notes, such stockholders held $56.2 million.

Note 17—Segment Information

The Company had two operating segments, (i) the exploration, development and production of oil, natural gas and NGL (the “exploration and production segment”) and (ii) the construction of and support of midstream assets to gather and process crude oil and gas production (the “gathering and facilities segment”). Elevation Midstream, LLC comprised the gathering and facilities segment. Through March 16, 2020, the results of Elevation were included in the consolidated financial statements of Extraction. Effective March 17, 2020, the results of Elevation Midstream, LLC are no longer consolidated in Extraction’s results; however, the Company’s prior quarter segment disclosures included the gathering and facilities segment because it was consolidated through March 16, 2020. Please see Note 1 — Business and Organization — Deconsolidation of Elevation Midstream, LLC for further information. After March 31, 2020, the Company had a single reportable segment.

Financial information of the Company’s reportable segments was as follows for the years ended December 31, 2020 and 2019 (in thousands).

|  | For the Year Ended December 31, 2020 |
|  | Exploration and Production |  |  | Gathering and Facilities |  |  | Elimination of Intersegment Transactions |  |  | Consolidated Total |
Revenues: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Revenues from third parties |  |  | 556,431 |  |  |  | 1,473 |  |  |  | — |  |  | $ | 557,904 |
Revenues from Extraction |  |  | — |  |  |  | 4,513 |  |  |  | (4,513 | ) |  |  | — |
Total Revenues |  | $ | 556,431 |  |  | $ | 5,986 |  |  | $ | (4,513 | ) |  | $ | 557,904 |
Operating Expenses and Other Income (Expense): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Direct operating expenses |  | $ | (249,720 | ) |  | $ | (3,935 | ) |  | $ | 4,294 |  |  | $ | (249,361 | )
Depletion, depreciation, amortization and accretion |  |  | (331,220 | ) |  |  | (1,099 | ) |  |  | — |  |  |  | (332,319 | )
Interest income |  |  | 88 |  |  |  | 29 |  |  |  | — |  |  |  | 117 |
Interest expense |  |  | (57,143 | ) |  |  | — |  |  |  | — |  |  |  | (57,143 | )
Earnings in unconsolidated subsidiaries |  |  | — |  |  |  | 480 |  |  |  | — |  |  |  | 480 |
Subtotal Operating Expenses and Other Income (Expense): |  | $ | (637,995 | ) |  | $ | (4,525 | ) |  | $ | 4,294 |  |  | $ | (638,226 | )
Segment Assets |  | $ | 2,025,199 |  |  | $ | — |  |  | $ | — |  |  | $ | 2,025,199 |
Capital Expenditures |  |  | 176,505 |  |  |  | (6,311 | ) |  |  | — |  |  |  | 170,194 |
Investment in Equity Method Investees |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Segment EBITDAX |  |  | 447,919 |  |  |  | 1,256 |  |  |  | — |  |  |  | 449,175 |

|  | For the Year Ended December 31, 2019 |
|  | Exploration and Production |  |  | Gathering and Facilities |  |  | Elimination of Intersegment Transactions |  |  | Consolidated Total |
Revenues: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Revenues from third parties |  | $ | 905,374 |  |  | $ | 1,261 |  |  | $ | — |  |  | $ | 906,635 |
Revenues from Extraction |  |  | — |  |  |  | 5,618 |  |  |  | (5,618 | ) |  |  | — |
Total Revenues |  | $ | 905,374 |  |  | $ | 6,879 |  |  | $ | (5,618 | ) |  | $ | 906,635 |
Operating Expenses and Other Income (Expense): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Direct operating expenses |  | $ | (223,707 | ) |  | $ | (2,258 | ) |  | $ | 5,131 |  |  | $ | (220,834 | )
Depletion, depreciation, amortization and accretion |  |  | (523,122 | ) |  |  | (1,415 | ) |  |  | — |  |  |  | (524,537 | )
Interest income |  |  | 449 |  |  |  | 1,379 |  |  |  | — |  |  |  | 1,828 |
Interest expense |  |  | (79,232 | ) |  |  | — |  |  |  | — |  |  |  | (79,232 | )
Earnings in unconsolidated subsidiaries |  |  | — |  |  |  | 2,285 |  |  |  | — |  |  |  | 2,285 |
Subtotal Operating Expenses and Other Income (Expense): |  | $ | (825,612 | ) |  | $ | (9 | ) |  | $ | 5,131 |  |  | $ | (820,490 | )
Segment Assets |  | $ | 2,554,893 |  |  | $ | 377,925 |  |  | $ | (5,861 | ) |  | $ | 2,926,957 |
Capital Expenditures |  |  | 597,677 |  |  |  | 202,624 |  |  |  | — |  |  |  | 800,301 |
Investment in Equity Method Investees |  |  | — |  |  |  | 44,584 |  |  |  | — |  |  |  | 44,584 |
Segment EBITDAX |  |  | 607,560 |  |  |  | 3,653 |  |  |  | (487 | ) |  |  | 610,726 |

The following table presents a reconciliation of Adjusted EBITDAX by segment to the GAAP financial measure of income (loss) before income taxes for the years ended December 31, 2020 and 2019 (in thousands).

|  | For the Year Ended December 31, 2020 |  |  | For the Year Ended December 31, 2019 |
Reconciliation of Adjusted EBITDAX to Income (Loss) Before Income Taxes |  |  |  |  |  |  |  |
Exploration and production segment EBITDAX |  | $ | 447,919 |  |  | $ | 607,560 |
Gathering and facilities segment EBITDAX |  |  | 1,256 |  |  |  | 3,653 |
Elimination of intersegment transactions segment EBITDAX |  |  | — |  |  |  | (487 | )
Subtotal of Reportable Segments |  | $ | 449,175 |  |  | $ | 610,726 |
Less: |  |  |  |  |  |  |  |
Depletion, depreciation, amortization and accretion |  |  | (332,319 | ) |  |  | (524,537 | )
Impairment of long lived assets |  |  | (208,463 | ) |  |  | (1,337,996 | )
Other operating expenses |  |  | (79,615 | ) |  |  | — |
Exploration and abandonment expenses |  |  | (258,932 | ) |  |  | (88,794 | )
Gain on sale of property and equipment and assets of unconsolidated subsidiary |  |  | 122 |  |  |  | (421 | )
Commodity derivative gain (loss) |  |  | 164,968 |  |  |  | (37,107 | )
Settlements on commodity derivative instruments |  |  | (188,822 | ) |  |  | 5,790 |
Premiums paid for derivatives that settled during the period |  |  | — |  |  |  | 18,929 |
Stock-based compensation expense |  |  | (6,511 | ) |  |  | (43,954 | )
Amortization of debt issuance costs |  |  | (3,685 | ) |  |  | (5,482 | )
Interest expense |  |  | (53,458 | ) |  |  | (84,236 | )
Gain on repurchase of 2026 Senior Notes |  |  | — |  |  |  | 10,486 |
Loss on deconsolidation of Elevation Midstream, LLC |  |  | (73,139 | ) |  |  | — |
Reorganization items, net |  |  | (676,855 | ) |  |  | — |
Income (Loss) Before Income Taxes |  | $ | (1,267,534 | ) |  | $ | (1,476,596 | )

Note 18—Supplemental Oil and Gas Reserve Information (Unaudited)

Results of Operations for Oil, Natural Gas and NGL Producing Properties

The following are the results of operations (in thousands) of the Company’s oil and gas producing activities, before corporate overhead and interest expenses. The Company assumed a statutory rate of 24.7% for the years ended December 31, 2020 and 2019.

|  | For the Year Ended December 31, |
|  | 2020 |  |  | 2019 |
Revenues |  | $ | 556,431 |  |  | $ | 905,374 |
Operating Expenses: |  |  |  |  |  |  |  |
Production expenses |  |  | 245,426 |  |  |  | 218,576 |
Exploration and abandonment expenses |  |  | 258,932 |  |  |  | 88,794 |
Depletion, depreciation, amortization and accretion |  |  | 332,319 |  |  |  | 524,537 |
Impairment of proved properties |  |  | 208,463 |  |  |  | 1,337,996 |
Results of operations before income tax benefit (expense) |  |  | (488,709 | ) |  |  | (1,264,529 | )
Income tax benefit (expense) |  |  | 120,711 |  |  |  | 312,339 |
Results of Operations |  | $ | (367,998 | ) |  | $ | (952,190 | )

Oil, Natural Gas and NGL Reserve Quantities (Unaudited)

The reserves at December 31, 2020 and 2019 presented below were prepared by the independent engineering firm Ryder Scott Company, L.P. All reserves are located within the DJ Basin. Proved oil, natural gas and NGL reserves are the estimated quantities of oil, natural gas and NGL which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions (i.e., prices and costs) existing at the time the estimate is made. Proved developed oil, natural gas and NGL reserves are proved reserves that can be expected to be recovered through existing wells and equipment in place and under operating methods being utilized at the time the estimates were made. The principal methodologies employed are decline curve analysis and analogy. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available.

The following table sets forth information for the years ended December 31, 2020 and 2019 with respect to changes in the Company’s proved (i.e., proved developed and undeveloped) reserves:

|  | Crude Oil |  |  | Natural Gas |  |  | NGL |  |  | MBoe |
|  | Mbbls |  |  | MMcf |  |  | Mbbls |  |  | Total |
Balance as of January 1, 2019 |  |  | 135,845 |  |  |  | 703,268 |  |  |  | 94,850 |  |  |  | 347,908 |
Revisions of previous estimates |  |  | (41,255 | ) |  |  | (118,365 | ) |  |  | (29,554 | ) |  |  | (90,537 | )
Purchase of reserves |  |  | 275 |  |  |  | 1,526 |  |  |  | 217 |  |  |  | 746 |
Extensions, discoveries, and other additions |  |  | 14,620 |  |  |  | 72,880 |  |  |  | 8,425 |  |  |  | 35,191 |
Sale of reserves |  |  | (2,590 | ) |  |  | (14,510 | ) |  |  | (1,765 | ) |  |  | (6,773 | )
Production |  |  | (15,436 | ) |  |  | (64,710 | ) |  |  | (6,164 | ) |  |  | (32,386 | )
Balance as of December 31, 2019 |  |  | 91,459 |  |  |  | 580,089 |  |  |  | 66,009 |  |  |  | 254,149 |
Revisions of previous estimates |  |  | (38,281 | ) |  |  | (163,718 | ) |  |  | (21,741 | ) |  |  | (87,308 | )
Purchase of reserves |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Extensions, discoveries, and other additions |  |  | 5,347 |  |  |  | 31,035 |  |  |  | 3,025 |  |  |  | 13,545 |
Sale of reserves |  |  | (590 | ) |  |  | (5,561 | ) |  |  | (453 | ) |  |  | (1,971 | )
Production |  |  | (12,543 | ) |  |  | (72,311 | ) |  |  | (7,945 | ) |  |  | (32,540 | )
Balance as of December 31, 2020 |  |  | 45,392 |  |  |  | 369,534 |  |  |  | 38,895 |  |  |  | 145,875 |
Proved Developed Reserves, included above |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Balance as of December 31, 2019 |  |  | 45,807 |  |  |  | 350,309 |  |  |  | 39,001 |  |  |  | 143,193 |
Balance as of December 31, 2020 |  |  | 33,367 |  |  |  | 288,769 |  |  |  | 30,797 |  |  |  | 112,292 |
Proved Undeveloped Reserves, included above |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Balance as of December 31, 2019 |  |  | 45,652 |  |  |  | 229,781 |  |  |  | 27,008 |  |  |  | 110,957 |
Balance as of December 31, 2020 |  |  | 12,025 |  |  |  | 80,765 |  |  |  | 8,098 |  |  |  | 33,583 |

• | The values for the 2020 oil, natural gas and NGL reserves are based on the 12-month arithmetic average of the first day of the month prices for the period from January through December 31, 2020. The unweighted arithmetic average first-day-of-the-month prices for the prior twelve months were $39.57 per barrel (West Texas Intermediate price) for crude oil and NGL and $1.99 per MMBtu (Henry Hub price) for natural gas. All prices are then further adjusted for transportation, quality and basis differentials. The average resulting price used as of December 31, 2020 was $33.60 per barrel for oil, $0.35 per Mcf for natural gas and $10.45 per barrel for NGL.
• | The values for the 2019 oil, natural gas and NGL reserves are based on the 12-month arithmetic average of the first day of the month prices for the period from January through December 31, 2019. The unweighted arithmetic average first-day-of-the-month prices for the prior twelve months were $55.69 per barrel (West Texas Intermediate price) for crude oil and NGL and $2.58 per MMBtu (Henry Hub price) for natural gas. All prices are then further adjusted for transportation, quality and basis differentials. The average resulting price used as of December 31, 2019 was $48.09 per barrel for oil, $1.04 per Mcf for natural gas and $13.87 per barrel for NGL.

For the year ended December 31, 2020, the Company had downward revisions of previous estimates of 87,308 MBoe primarily due to revisions of PUD expirations due to the SEC’s five year drilling rule caused by the change in business strategy to focus on being cash flow positive rather than maximizing reserves growth. Additionally, downward revisions were due to altering the development plan to increase the spacing between wellbores, thus drilling fewer wells, as well as negative performance revisions. As a result of ongoing drilling and completion activities during 2020, the Company reported extensions, discoveries, and other additions of 13,545 MBoe. Additionally, during 2020 the Company sold reserves of 1,971 MBoe and purchased no reserves.

For the year ended December 31, 2019, the Company had downward revisions of previous estimates of 90,537 MBoe. As a result of ongoing drilling and completion activities during 2019, the Company reported extensions, discoveries, and other additions of 35,191 MBoe. Additionally, during 2019 the Company sold reserves of 6,773 MBoe and purchased reserves of 746 MBoe.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil, Natural Gas and NGL Reserves

The Company follows the guidelines prescribed in ASC 932, Extractive Activities-Oil and Gas for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. The following summarizes the policies used in the preparation of the accompanying oil, natural gas and NGL reserve disclosures, standardized measures of discounted future net cash flows from proved oil, natural gas and NGL reserves and the reconciliations of standardized measures from year to year.

The information is based on estimates of proved reserves attributable to the Company’s interest in oil and gas properties as of December 31 of the years presented. These estimates were prepared by Ryder Scott Company L.P., independent petroleum engineers.

The standardized measure of discounted future net cash flows from production of proved reserves was developed as follows: (1) Estimates are made of quantities of proved reserves and future periods during which they are expected to be produced based on year-end economic conditions. (2) The estimated future cash flows are compiled by applying the trailing twelve-month average of the first of the month prices applied to the Company’s proved reserve year-end quantities. (3) The future cash flows are reduced by estimated production costs, costs to develop and produce the proved reserves and abandonment costs, all based on year-end economic conditions, plus Company overhead incurred. (4) Future net cash flows are discounted to present value by applying a discount rate of 10%.

The assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC. These assumptions do not necessarily reflect the Company’s expectations of actual revenues to be derived from those reserves, nor their present value. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations, since these reserve quantity estimates are the basis for the valuation process. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and gas properties. The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair value of the Company’s oil and natural gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.

The following summary sets forth the Company’s future net cash flows relating to proved oil, natural gas and NGL reserves based on the standardized measure prescribed in ASC 932, Extractive Activities-Oil and Gas (in thousands):

|  | For the Year Ended December 31, |
|  | 2020 |  |  | 2019 |
Future crude oil, natural gas and NGL sales |  | $ | 2,062,787 |  |  | $ | 5,914,900 |
Future production costs |  |  | (732,455 | ) |  |  | (2,166,852 | )
Future development costs |  |  | (209,074 | ) |  |  | (798,225 | )
Future income tax expense |  |  | — |  |  |  | (7,647 | )
Future net cash flows |  | $ | 1,121,258 |  |  | $ | 2,942,176 |
10% annual discount |  |  | (326,825 | ) |  |  | (1,038,303 | )
Standardized measure of discounted future net cash flows (1) |  | $ | 794,433 |  |  | $ | 1,903,873 |

| (1) | For the years ended December 31, 2020 and 2019, future income tax expenses in the Company’s calculation of the standardized measure of discounted future net cash flows are based on year-end statutory tax rates giving effect to the remaining tax basis in the oil and gas properties, other deductions, credit and allowances relating to the Company’s proved reserves. For purposes of the standardized measure calculation, it was assumed that all of the Company’s operations are attributable to the Company’s oil and gas assets.

The following are the principal sources of change in the standardized measure (in thousands):

|  | For the Year Ended December 31, |
|  | 2020 |  |  | 2019 |
Balance at beginning of period |  | $ | 1,903,873 |  |  | $ | 2,899,983 |
Sales of crude oil, natural gas and NGL, net |  |  | (306,711 | ) |  |  | (681,667 | )
Net change in prices and production costs |  |  | (594,367 | ) |  |  | (878,838 | )
Net change in future development costs |  |  | 60,901 |  |  |  | 3,147 |
Extensions and discoveries |  |  | 62,858 |  |  |  | 256,147 |
Acquisitions of reserves |  |  | — |  |  |  | 9,623 |
Sale of reserves |  |  | (15,506 | ) |  |  | (52,710 | )
Revisions of previous quantity estimates |  |  | (559,839 | ) |  |  | (560,397 | )
Previously estimated development costs incurred |  |  | 115,095 |  |  |  | 348,137 |
Net changes in income taxes |  |  | 2,779 |  |  |  | 347,057 |
Accretion of discount |  |  | 172,408 |  |  |  | 324,981 |
Changes in production timing and other |  |  | (47,058 | ) |  |  | (111,590 | )
Balance at end of period |  | $ | 794,433 |  |  | $ | 1,903,873 |