Extraction Oil & Gas (XOG) 10-Q 2020 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2020

OR

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

For the transition period from                         to                         

Commission file number 001-37907

EXTRACTION OIL & GAS, INC.

(Exact name of registrant as specified in its charter)

Delaware			46-1473923
(State or other jurisdiction of incorporation or organization)			(IRS Employer Identification No.)
370 17th Street
Suite 5300
Denver,	Colorado	80202
(Address of principal executive offices)

(720) 557-8300

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:
Title of each class	Trading Symbol(s)	Name of exchange on which registered
Common Stock, par value $0.01	XOG	NASDAQ Global Select Market

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ☒    No  ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    Yes  ☒    No  ☐

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

Large Accelerated Filer	☐	Accelerated Filer	☒
Non-Accelerated Filer	☐	Smaller Reporting Company	☐
		Emerging Growth Company	☐

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ☐    No  ☒

The total number of shares of common stock, par value $0.01 per share, outstanding as of May 8, 2020 was 138,135,046.

EXTRACTION OIL & GAS, INC.

TABLE OF CONTENTS

		Page
PART I—FINANCIAL INFORMATION
Item 1.	Condensed Consolidated Financial Statements (Unaudited)	2
	Condensed Consolidated Balance Sheets as of March 31, 2020 and December 31, 2019	2
	Condensed Consolidated Statements of Operations for the three months ended March 31, 2020 and 2019	3
	Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2020 and 2019	4
	Condensed Consolidated Statements of Changes in Stockholders’ Equity and Noncontrolling Interest for the three months ended March 31, 2020 and 2019	5
	Notes to the Unaudited Condensed Consolidated Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	30
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	49
Item 4.	Controls and Procedures	50
PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	52
Item 1A.	Risk Factors	52
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	55
Item 3.	Defaults upon Senior Securities	55
Item 4.	Mine Safety Disclosures	55
Item 5.	Other Information	55
Item 6.	Exhibits	56
	Signatures	57

1

PART I. FINANCIAL INFORMATION

ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS

EXTRACTION OIL & GAS, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)

(Unaudited)

	March 31, 2020		December 31, 2019
ASSETS
Current Assets:
Cash and cash equivalents	$	31,993	$	32,382
Accounts receivable
Trade	49,878		32,009
Oil, natural gas and NGL sales	38,850		105,103
Inventory, prepaid expenses and other	34,494		36,702
Commodity derivative asset	164,330		17,554
Total Current Assets	319,545		223,750
Property and Equipment (successful efforts method), at cost:
Proved oil and gas properties	4,676,967		4,530,934
Unproved oil and gas properties	417,021		524,214
Wells in progress	154,981		149,733
Less: accumulated depletion, depreciation, amortization and impairment charges	(3,057,098)		(2,985,983)
Net oil and gas properties	2,191,871		2,218,898
Gathering systems and facilities, net of accumulated depreciation	—		315,777
Other property and equipment, net of accumulated depreciation	72,589		72,542
Net Property and Equipment	2,264,460		2,607,217
Non-Current Assets:
Commodity derivative asset	88,783		13,229
Other non-current assets	30,600		82,761
Total Non-Current Assets	119,383		95,990
Total Assets	$	2,703,388	$	2,926,957
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities	$	163,057	$	190,864
Accounts payable and accrued liabilities, related party	46,777		—
Revenue payable	104,702		108,493
Production taxes payable	115,556		115,489
Commodity derivative liability	716		1,998
Accrued interest payable	18,042		20,625
Asset retirement obligations	15,328		27,058
Total Current Liabilities	464,178		464,527
Non-Current Liabilities:
Credit facility	470,000		470,000
Senior Notes, net of unamortized debt issuance costs	1,086,347		1,085,777
Production taxes payable	119,675		98,740
Commodity derivative liability	—		108
Other non-current liabilities	59,689		54,579
Asset retirement obligations	78,445		68,850
Deferred tax liability	2,200		—
Total Non-Current Liabilities	1,816,356		1,778,054
Total Liabilities	2,280,534		2,242,581
Commitments and Contingencies—Note 13
Series A Convertible Preferred Stock, $0.01 par value; 50,000,000 shares authorized, 185,280 issued and outstanding	182,157		175,639
Stockholders' Equity:
Common stock, $0.01 par value; 900,000,000 share authorized; 137,891,740 and 137,657,922 issued and outstanding, respectively	1,336		1,336
Treasury stock, at cost, 38,859,078 shares	(170,138)		(170,138)
Additional paid-in capital	2,143,670		2,156,383
Accumulated deficit	(1,734,171)		(1,743,208)
Total Extraction Oil & Gas, Inc. Stockholders' Equity	240,697		244,373
Noncontrolling interest	—		264,364
Total Stockholders' Equity	240,697		508,737
Total Liabilities and Stockholders' Equity	$	2,703,388	$	2,926,957

THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF

THESE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

2

EXTRACTION OIL & GAS, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

(Unaudited)

	For the Three Months Ended March 31,
	2020		2019
Revenues:
Oil sales	$	124,219	$	165,424
Natural gas sales	22,302		35,892
NGL sales	17,193		20,601
Gathering and compression	1,473		—
Total Revenues	165,187		221,917
Operating Expenses:
Lease operating expense	30,390		21,857
Midstream operating expenses	3,935		—
Transportation and gathering	22,786		10,365
Production taxes	13,454		18,129
Exploration and abandonment expenses	112,480		6,194
Depletion, depreciation, amortization and accretion	76,051		118,770
Impairment of long lived assets	775		8,248
Gain on sale of property and equipment	—		(222)
General and administrative expense	10,596		27,652
Other operating expenses	52,575		—
Total Operating Expenses	323,042		210,993
Operating Income (Loss)	(157,855)		10,924
Other Income (Expense):
Commodity derivative gain (loss)	263,015		(122,091)
Loss on deconsolidation of Elevation Midstream, LLC	(73,139)		—
Interest expense	(21,358)		(13,008)
Other income	574		1,143
Total Other Income (Expense)	169,092		(133,956)
Income (Loss) Before Income Taxes	11,237		(123,032)
Income tax (expense) benefit	(2,200)		29,000
Net Income (Loss)	$	9,037	$	(94,032)
Net income attributable to noncontrolling interest	6,160		3,975
Net Income (Loss) Attributable to Extraction Oil & Gas, Inc.	2,877		(98,007)
Adjustments to reflect Series A Preferred Stock dividends and accretion of discount	(6,518)		(4,317)
Net Loss Available to Common Shareholders, Basic and Diluted	$	(3,641)	$	(102,324)
Loss Per Common Share (Note 12)
Basic and diluted	$	(0.03)	$	(0.60)
Weighted Average Common Shares Outstanding
Basic and diluted	137,726		170,702

THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF

THESE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

3

EXTRACTION OIL & GAS, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

	For the Three Months Ended March 31,
	2020		2019
Cash flows from operating activities:
Net income (loss)	$	9,037	$	(94,032)
Reconciliation of net income (loss) to net cash provided by operating activities:
Depletion, depreciation, amortization and accretion	76,051		118,770
Abandonment and impairment of unproved properties	106,928		3,893
Impairment of long lived assets	775		8,248
Gain on sale of property and equipment	—		(222)
Gain on repurchase of 2026 Senior Notes	—		(7,317)
Amortization of debt issuance costs	1,242		1,498
Non-cash lease expense	4,871		2,486
Contract asset	8,465		—
Commodity derivatives (gain) loss	(263,015)		122,091
Settlements on commodity derivatives	24,932		(3,538)
Earnings in unconsolidated subsidiaries	(480)		(338)
Loss on deconsolidation of Elevation Midstream, LLC	73,139		—
Distributions from unconsolidated subsidiaries	—		1,751
Deferred income tax expense (benefit)	2,200		(29,000)
Stock-based compensation	—		13,008
Changes in current assets and liabilities:
Accounts receivable—trade	(9,127)		11,908
Accounts receivable—oil, natural gas and NGL sales	66,253		2,981
Inventory, prepaid expenses and other	584		136
Accounts payable and accrued liabilities	(7,699)		(10,638)
Accounts payable and accrued liabilities, related party	46,777		—
Revenue payable	(1,690)		(21,506)
Production taxes payable	21,002		22,919
Accrued interest payable	(2,583)		(4,429)
Asset retirement expenditures	(10,563)		(4,558)
Net cash provided by operating activities	147,099		134,111
Cash flows from investing activities:
Oil and gas property additions	(143,000)		(188,027)
Sale of property and equipment	12,117		16,521
Gathering systems and facilities additions, net of cost reimbursements	4,193		(49,175)
Other property and equipment additions	(2,980)		(8,213)
Investment in unconsolidated subsidiaries	(10,033)		(4,929)
Distributions from unconsolidated subsidiary, return of capital	—		1,448
Net cash used in investing activities	(139,703)		(232,375)
Cash flows from financing activities:
Borrowings under credit facility	70,000		65,000
Repayments under credit facility	(70,000)		(25,000)
Repurchase of 2026 Senior Notes	—		(28,460)
Repurchase of common stock	—		(32,212)
Payment of employee payroll withholding taxes	(35)		(454)
Dividends on Series A Preferred Stock	—		(2,721)
Debt and equity issuance costs	(22)		(94)
Preferred Unit issuance costs	—		(10)
Net cash used in financing activities	(57)		(23,951)
Effect of deconsolidation of Elevation Midstream, LLC	(7,728)		—
Decrease in cash and cash equivalents	(389)		(122,215)
Cash, cash equivalents at beginning of period	32,382		234,986
Cash, cash equivalents at end of the period	$	31,993	$	112,771
Supplemental cash flow information:
Property and equipment included in accounts payable and accrued liabilities	$	99,602	$	143,168
Cash paid for interest	$	24,865	$	25,265
Accretion of beneficial conversion feature of Series A Preferred Stock	$	1,770	$	1,596
Preferred Units commitment fees and dividends paid-in-kind	$	6,160	$	3,975
Series A Preferred Stock dividends paid-in-kind	$	4,748	$	—

THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF

THESE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

4

EXTRACTION OIL & GAS, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

STOCKHOLDERS’ EQUITY AND NONCONTROLLING INTEREST

(In thousands)

(Unaudited)

	Common Stock				Treasury Stock						Additional Paid in Capital		Accumulated Deficit		Extraction Oil & Gas, Inc. Stockholders' Equity			Noncontrolling Interest	Total Stockholders' Equity
	Shares	Amount		Shares	Amount												Amount
Balance at January 1, 2020	176,517	$	1,336	38,859	$	(170,138)	$	2,156,383	$	(1,743,208)	$	244,373	$	264,364	$	508,737
Preferred Units commitment fees & dividends paid-in-kind	—	—		—	—		(6,160)		—		(6,160)		6,160		—
Series A Preferred Stock dividends	—	—		—	—		(4,748)		—		(4,748)		—		(4,748)
Accretion of beneficial conversion feature on Series A Preferred Stock	—	—		—	—		(1,770)		—		(1,770)		—		(1,770)
Restricted stock issued, net of tax withholdings and other	234	—		—	—		(35)		—		(35)		—		(35)
Net income	—	—		—	—		—		9,037		9,037		—		9,037
Effects of deconsolidation of Elevation Midstream, LLC	—	—		—	—		—		—		—		(270,524)		(270,524)
Balance at March 31, 2020	176,751	$	1,336	38,859	$	(170,138)	$	2,143,670	$	(1,734,171)	$	240,697	$	—	$	240,697

	Common Stock				Treasury Stock						Additional Paid in Capital		Accumulated Deficit		Extraction Oil & Gas, Inc. Stockholders' Equity			Noncontrolling Interest	Total Stockholders' Equity
	Shares	Amount		Shares	Amount												Amount
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 issuance costs	—	—		—	—		—		—		—		(10)		(10)
Preferred Units commitment fees & dividends paid-in-kind	—	—		—	—		(3,975)		—		(3,975)		3,975		—
Stock-based compensation	—	—		—	—		13,008		—		13,008		—		13,008
Series A Preferred Stock dividends	—	—		—	—		(2,721)		—		(2,721)		—		(2,721)
Accretion of beneficial conversion feature on Series A Preferred Stock	—	—		—	—		(1,596)		—		(1,596)		—		(1,596)
Repurchase of common stock	—	(77)		7,824	(32,135)		—		—		(32,212)		—		(32,212)
Restricted stock issued, net of tax withholdings	270	—		—	—		(454)		—		(454)		—		(454)
Net loss	—	—		—	—		—		(94,032)		(94,032)		—		(94,032)
Balance at March 31, 2019	176,480	$	1,601	12,367	$	(64,872)	$	2,157,923	$	(469,820)	$	1,624,832	$	151,837	$	1,776,669

THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF

THESE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

5

EXTRACTION OIL & GAS, INC.

NOTES TO THE UNAUDITED CONDENSED 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 well as the construction and support of midstream assets to gather and process crude oil and gas production. Extraction is a public company listed for trading on the NASDAQ Global Select Market under the symbol "XOG."

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. Midstream assets of Elevation are represented as the gathering systems and facilities line item within the condensed consolidated balance sheets.

During the first quarter of 2020, Elevation's non-controlling interest owner, which owns 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 condensed consolidated statements of operations for the three months ended March 31, 2020. Also, as of 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 Accounting Standards Codification 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.

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 will account for Elevation under the cost method of accounting. The Company reserves all rights related to actions taken by Elevation’s board of managers.

Note 2—Basis of Presentation, Significant Accounting Policies and Recent Accounting Pronouncements

Basis of Presentation

The unaudited condensed consolidated financial statements include the accounts of the Company, including its wholly owned 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 generally accepted accounting principles in the United States (“GAAP”) and the Securities and Exchange Commission rules and regulation for interim financial reporting. In the opinion of management, all adjustments, consisting primarily of normal recurring accruals that are considered necessary for a fair statement of the unaudited condensed consolidated financial information, have been included. However, operating results for the period presented are not necessarily indicative of the results that may be expected for a full year. Interim condensed consolidated financial

6

statements and the year-end balance sheets do not include all of the information and notes required by GAAP for audited annual consolidated financial statements. These unaudited condensed consolidated financial statements should be read in conjunction with the Company’s audited consolidated financial statements and notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2019 (“Annual Report”).

Significant Accounting Policies

The significant accounting policies followed by the Company are set forth in Note 2 to the Company’s consolidated financial statements in its Annual Report and are supplemented by the notes to the unaudited condensed consolidated financial statements in this report. These unaudited condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes included in the Company’s Annual Report.

Revenue — Contract Balances

The Company has a certain revenue contract with an initial term beginning on November 1, 2016 and continuing until October 31, 2020 after which the contract begins an automatic month-to-month renewal unless terminated by either party giving notice at least 180 days prior to the effective termination date but in no event can 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 ends on April 30, 2021 because it may be terminated by either party with no penalty effective as of such date. The contract term impacts the amount of consideration that can be included in the transaction price. Generally, under the Company's various sales contracts, the Company invoices customers once its performance obligations have been satisfied, at which point payment is unconditional. For the three months ended March 31, 2020, the Company allocated $8.5 million to a satisfied performance obligation recognized within oil sales under ASC 606. As of March 31, 2020, the Company estimated a performance obligation under ASC 606 of $46.2 million, of which $3.9 million is recorded in accounts payable and accrued liabilities and $42.3 million is recorded in other non-current liabilities. A corresponding asset was recorded in the amount of $13.0 million, of which $12.1 million is recorded in inventory, prepaid expenses and other and $0.9 million is recorded in other non-current assets. The asset will be amortized into revenue over the contractual term of the contract, and the liability will be relieved if a deficiency payment is made to the counterparty or when the Company's minimum volume commitments are fulfilled.

Other Operating Expenses

Other operating expenses were $52.6 million for the three months ended March 31, 2020. This amount is primarily made up of a $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 13—Commitments and Contingencies for further details. Also included in this amount is a $5.8 million charge to income for expenses related to a workforce reduction in February 2020.

Impairment of Oil and Gas Properties

The Company identified an impairment triggering event for its proved oil and gas properties as of March 31, 2020 due to the significant decrease in oil and gas prices during the first quarter of 2020. As such, the Company performed a quantitative assessment as of March 31, 2020, and proved property in its northern field was impaired. For the three months ended March 31, 2020 and 2019, the Company recognized $0.8 million and $8.2 million, respectively, in impairment expense on its proved oil and gas properties related to impairment of assets in its northern field. The fair value did not exceed the Company's carrying amount associated with its proved oil and gas properties in its northern field. The Company did not have any proved property impairment in its Core DJ Basin field, primarily because of the $1.3 billion impairment charge that was recorded in the fourth quarter of 2019.

Of the Company's $112.5 million in exploration and abandonment expenses for the three months ended March 31, 2020, $106.9 million was lease abandonment expense. 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

7

lease extension payments for unproved properties is reported in exploration and abandonment expenses in the condensed consolidated statements of operations.

Recent Accounting Pronouncements

In June 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("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, 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, 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 as of March 31, 2020.

Other than as disclosed above or in the Company’s Annual Report, there are no other accounting standards applicable to the Company as of March 31, 2020 and through the date of this filing that would have a material effect on the Company’s unaudited condensed consolidated financial statements and related disclosures that have been issued but not yet adopted by the Company.

Note 3—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 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.

8

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 4—Going Concern

The Company depends on cash flows from operating activities and, as necessary and available, borrowings under its senior secured revolving credit facility (the “revolving credit facility”) to fund its capital expenditures and working capital requirements. Additionally, the Company historically has used proceeds from the issuance of equity and debt securities in the capital markets and from sales or other monetizations of assets to fund its capital expenditures and working capital requirements.

The market price for oil, natural gas and NGLs decreased significantly beginning in the first quarter of 2020, continuing into the second quarter of 2020. The decrease in the market price for the Company’s production directly reduces the Company’s cash flow from operations and indirectly impacts its other potential sources of funds described above. The Company has reduced its 2020 upstream capital budget and as a result expects to suspend drilling in the second half of 2020 and does not see production returning to historical levels for the foreseeable future. As discussed in Note 5—Long-Term Debt, lenders under the revolving credit facility elected to reduce the borrowing base and elected commitments to $650.0 million from $950.0 million on April 27, 2020, and the Company borrowed all of its remaining available capacity under the revolving credit facility. As a result of the reduction of the borrowing base and elected commitments, it is probable that the Company will not meet the financial covenants under the revolving credit facility for the three months ended June 30, 2020 when assuming the Company’s current financial forecast.

If the Company does not obtain a waiver of its financial covenants for the three months ended June 30, 2020, the lenders under the revolving credit facility will be able to accelerate maturity of the debt. Any acceleration of the obligations under the revolving credit facility would result in a cross-default and potential acceleration of the maturity of the Company’s other outstanding long-term debt amounting to approximately $1.1 billion. These defaults create uncertainty associated with the Company’s ability to repay its outstanding long-term debt obligations as they become due and creates a substantial doubt over the Company’s ability to continue as a going concern.

As a result of the impacts to the Company’s financial position resulting from declining commodity price conditions and in consideration of the substantial amount of long-term debt and preferred stock outstanding, the Company has engaged advisors to assist with the evaluation of strategic alternatives, which may include, but not be limited to, seeking a restructuring, amendment or refinancing of existing debt through a private restructuring or reorganization under Chapter 11 of the Bankruptcy Code. However, there can be no assurances that the Company will be able to successfully restructure its indebtedness, improve its financial position or complete any strategic transactions. As a result of these uncertainties and the likelihood of a restructuring or reorganization, management has concluded that there is substantial doubt regarding the Company’s ability to continue as a going concern.

The consolidated financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets and satisfaction of liabilities and commitments in the normal course of business. The consolidated financial statements do not reflect any adjustments that might result if the Company is unable to continue as a going concern.

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Note 5—Long-Term Debt

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

	March 31, 2020		December 31, 2019
Credit facility due August 16, 2022 (or an earlier time as set forth in the credit facility)	$	470,000	$	470,000
2024 Senior Notes due May 15, 2024	400,000		400,000
2026 Senior Notes due February 1, 2026	700,189		700,189
Unamortized debt issuance costs on Senior Notes	(13,842)		(14,412)
Total long-term debt	1,556,347		1,555,777
Less: current portion of long-term debt	—		—
Total long-term debt, net of current portion	$	1,556,347	$	1,555,777

Credit Facility

In August 2017, the Company entered into an amendment and restatement of its existing credit facility (prior to amendment and restatement, the "Prior Credit Facility"), to provide aggregate commitments of $1.5 billion with a syndicate of banks, which is subject to a borrowing base. The credit facility matures on the earlier of (a) August 16, 2022, (b) April 15, 2021, if (and only if) (i) the Series A Preferred Stock have not been converted into common equity or redeemed prior to April 15, 2021 (the Company can redeem the Series A Preferred Stock at any time), and (ii) prior to April 15, 2021, the maturity date of the Series A Preferred Stock has not been extended to a date that is no earlier than six months after August 16, 2022 or (c) the earlier termination in whole of the commitments under the credit facility. No principal payments are generally required until the credit agreement matures or in the event that the borrowing base falls below the outstanding balance.

As of March 31, 2020, the credit facility had a maximum credit amount of $1.5 billion, subject to a borrowing base and elected commitments of $950.0 million. As of March 31, 2020 and December 31, 2019, the Company had outstanding borrowings of $470.0 million and had standby letters of credit of $49.5 million which reduces the availability of the undrawn borrowing base. At March 31, 2020, the undrawn balance under the credit facility was $480.0 million before letters of credit. The amount available to be borrowed under the Company’s revolving credit facility is subject to a borrowing base that is redetermined semiannually on each May 1 and November 1, and will depend on the volumes of the Company’s proved oil and gas reserves, commodity prices, estimated cash flows from these reserves and other information deemed relevant by the administrative agent under the Company’s revolving credit facility. Additionally, the undrawn balance may be constrained by the Company's quantitative covenants under the credit facility, including the current ratio and ratio of consolidated debt less cash balances to its consolidated EBITDAX, at the next required quarterly compliance date.

On April 27, 2020, the lenders under our revolving credit facility provided notice to the Company that they had completed the redetermination scheduled to occur on May 1, 2020, and via this redetermination, our borrowing base had been reduced from $950.0 million to $650.0 million. As of May 11, 2020, following this redetermination, the Company had outstanding borrowings of $600.5 million and had standby letters of credit of $49.5 million, which reduce the availability of the undrawn borrowing base. As of the date of this filing, the available balance under the credit facility was 0.

Principal amounts borrowed on the credit facility will be payable on the maturity date. We may repay any amounts borrowed prior to the maturity date without any premium or penalty other than customary LIBOR breakage costs. Amounts repaid under the credit facility may be re-borrowed from time to time, subject to the terms of the facility.

Interest on the credit facility is payable at one of the following two variable rates as selected by the Company: a base rate based on the Prime Rate or the Eurodollar rate, based on LIBOR. Either rate is adjusted upward by an applicable margin, based on the utilization percentage of the facility as outlined in the pricing grid below. Additionally, the credit facility provides for a commitment fee of 0.375% to 0.50%, depending on borrowing base usage. The grid below shows the Base Rate Margin and Eurodollar Margin depending on the applicable Borrowing Base Utilization Percentage (as defined in the credit facility) as of the date of this filing:

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Borrowing Base Utilization Grid 

					Eurodollar		Base Rate				Commitment
Borrowing Base Utilization Percentage	Utilization								Margin				Margin		Fee Rate
Level 1	<25%								1.50	%			0.50	%	0.38	%
Level 2	≥	25%	<	50%	1.75	%	0.75	%			0.38	%
Level 3	≥	50%	<	75%	2.00	%	1.00	%			0.50	%
Level 4	≥	75%	<	90%	2.25	%	1.25	%			0.50	%
Level 5	≥90%								2.50	%			1.50	%	0.50	%

The credit facility contains representations, warranties, covenants, conditions and defaults customary for transactions of this type, including but not limited to: (i) limitations on liens and incurrence of debt covenants; (ii) limitations on dividends, distributions, redemptions and restricted payments covenants; (iii) limitations on investments, loans and advances covenants; and (iv) limitations on the sale of property, mergers, consolidations and other similar transactions covenants. Additionally, the credit facility limits the Company entering into hedges in excess of 85% of its anticipated production volumes.

The credit facility also contains financial covenants requiring the Company to comply on the last day of each quarter with a current ratio of its restricted subsidiaries’ current assets (includes availability under the revolving credit facility and unrestricted cash and excludes derivative assets) to its restricted subsidiaries’ current liabilities (excludes obligations under the revolving credit facility, senior notes and certain derivative liabilities), of not less than 1.0 to 1.0 and to maintain, on the last day of each quarter, a ratio of its restricted subsidiaries’ debt less cash balances to its restricted subsidiaries EBITDAX (EBITDAX is defined as net income adjusted for interest expense, income tax expense/benefit, DD&A, exploration and abandonment expenses as well as certain non-recurring cash and non-cash charges and income (such as stock-based compensation expense, unrealized gains/losses on commodity derivatives and impairment of long-lived assets and goodwill), subject to pro forma adjustments for non-ordinary course acquisitions and divestitures) for the four fiscal quarter periods most recently ended, of not greater than 4.0 to 1.0 as of the last day of such fiscal quarter. As of March 31, 2020, the Company was in compliance with the covenants under the credit agreement.

The Company’s 2020 capital program remains focused on generating free cash flow with an emphasis on strengthening liquidity and the balance sheet as the Company works to pay down debt. However, factors including those outside of the Company’s control may prevent maintaining compliance with such covenants, including commodity price declines and the Company's inability to access capital markets, to access the asset sale market or to execute on its business plan. Additionally, as a result of the reduction of the borrowing base and elected commitments described above, it is probable that the Company will not meet the financial covenants under the revolving credit facility for the three months ended June 30, 2020 under the Company’s current financial forecast. The Company may seek covenant relief from the lenders under the revolving credit facility, and if the Company does not obtain a waiver of its financial covenants for the three months ended June 30, 2020, the lenders under the revolving credit facility will be able to declare all outstanding principal and interest to be due and payable, and the lenders under the credit agreement could terminate their commitments to loan money and could foreclose against the assets collateralizing their borrowings. Any acceleration of the obligations under the revolving credit facility would result in a cross-default and potential acceleration of the maturity of the Company’s other outstanding long-term debt.

Any borrowings under the credit facility are collateralized by substantially all of the assets of the Company and certain of its subsidiaries, including oil and gas properties, personal property and the equity interests of those subsidiaries of the Company. The Company has entered into oil and natural gas hedging transactions with several counterparties that are also lenders under the credit facility. The Company’s obligations under these hedging contracts are secured by the collateral securing the credit facility. Elevation is an unrestricted subsidiary, which is no longer consolidated or controlled by the Company, and the assets and credit of Elevation are not available to satisfy the debts and other obligations of the Company or its other subsidiaries.

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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 bear an annual interest rate of 7.375%. The interest on the 2024 Senior Notes is 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 are its senior unsecured obligations and rank 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 are 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 credit facility (the "2024 Senior Notes Guarantors"). The 2024 Senior Notes are effectively subordinated to all of the Company's secured indebtedness (including all borrowings and other obligations under its revolving 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 do not guarantee the 2024 Senior Notes.

The 2024 Senior Notes also contain affirmative and negative covenants that, among other things, limit 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 contains customary events of default. Upon the occurrence of events of default arising from certain events of bankruptcy or insolvency, the 2024 Senior Notes shall 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 may declare all outstanding 2024 Senior Notes to be due and payable immediately.

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 of the 2026 Senior Notes, the "2026 Senior Notes Offering"). The 2026 Senior Notes bear an annual interest rate of 5.625%. The interest on the 2026 Senior Notes is 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's 2026 Senior Notes are the Company's senior unsecured obligations and rank 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 are 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 credit facility (the "2026 Senior Notes Guarantors"). The 2026 Senior Notes are effectively subordinated to all of the Company's secured indebtedness (including all borrowings and other obligations under the Company's revolving 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 contain affirmative and negative covenants that, among other things, limit 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

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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 contains customary events of default. Upon the occurrence of events of default arising from certain events of bankruptcy or insolvency, the 2026 Senior Notes shall 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 may declare all outstanding 2026 Senior Notes to be due and payable immediately.

Debt Issuance Costs

As of March 31, 2020, the Company had debt issuance costs, net of accumulated amortization, of $2.2 million related to its credit facility which has been reflected on the Company's condensed consolidated balance sheets within the line item other non-current assets. As of March 31, 2020, the Company had debt issuance costs net of accumulated amortization of $13.8 million related to its 2024 and 2026 Senior Notes which have been reflected on the Company's condensed consolidated balance sheets within the line item Senior Notes, net of unamortized debt issuance costs. Debt issuance costs include origination, legal, engineering, and other fees incurred in connection with the Company’s credit facility and Senior Notes. For the three months ended March 31, 2020 and March 31, 2019, the Company recorded amortization expense related to the debt issuance costs of $1.2 million and $1.5 million, respectively.

Interest Incurred on Long-Term Debt

For the three months ended March 31, 2020, the Company incurred interest expense on long-term debt of $22.3 million as compared to $20.8 million for the three months ended March 31, 2019. For the three months ended March 31, 2020, the Company capitalized interest expense on long term debt of $2.1 million as compared to $2.0 million for the three months ended March 31, 2019, which has been reflected in the Company’s consolidated financial statements.

Senior Note Repurchase Program

On January 4, 2019, the Board of Directors 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 is subject to restrictions under our credit facility and does not obligate it to acquire any specific nominal amount of Senior Notes. For the three months ended March 31, 2020, the Company did not repurchase any Senior Notes. For the three months ended March 31, 2019, the Company repurchased a nominal value of $35.8 million for $28.5 million in connection with the Senior Notes Repurchase Program. Interest expense for the three months ended March 31, 2019 included a $7.3 million gain on debt repurchase related to the Company's Senior Note Repurchase Program.

Note 6—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.

A swap has an established fixed price. When the settlement price is below the fixed price, the counterparty pays the Company an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is above the fixed price, the Company pays its counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume.

A put option has an established floor price. The buyer of the put option pays the seller a premium to enter into the put option. When the settlement price is below the floor price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is above the floor price, the put option expires worthless. Some of the Company’s purchased put options have deferred premiums. For the deferred premium puts, the Company agrees to pay a premium to the counterparty at the time of settlement.

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A call option has an established ceiling price. The buyer of the call option pays the seller a premium to enter into the call option. When the settlement price is above the ceiling price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is below the ceiling price, the call option expires worthless.

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 objective of the Company’s use of commodity derivative instruments is to achieve more predictable cash flows in an environment of volatile oil and 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 our revenues, we have periodically entered into commodity derivative contracts with respect to certain of our oil and natural gas production through various transactions that limit the downside of future prices received. We plan to continue our practice of entering into such transactions to reduce the impact of commodity price volatility on our cash flow from operations. Future transactions may include price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty. Additionally, we may enter into collars, whereby we receive 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 prices at targeted levels and to manage our exposure to oil 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 9 counterparties, all but one of whom are lenders under our credit agreement. 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 is 0 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.

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

	2020		2021		2022		2023
NYMEX WTI Crude Swaps:
Notional volume (Bbl)	2,800,000		4,200,000		1,020,000		900,000
Weighted average fixed price ($/Bbl)	$	59.75	$	57.10	$	54.84	$	54.87
NYMEX WTI Crude Purchased Puts:
Notional volume (Bbl)	5,300,000		3,600,000		—		—
Weighted average purchased put price ($/Bbl)	$	54.83	$	54.17	$	—	$	—
NYMEX WTI Crude Purchased Calls:
Notional volume (Bbl)	250,000		—		—		—
Weighted average purchased call price ($/Bbl)	$	57.06	$	—	$	—	$	—
NYMEX WTI Crude Sold Calls:
Notional volume (Bbl)	6,250,000		3,600,000		—		—
Weighted average sold call price ($/Bbl)	$	61.94	$	61.93	$	—	$	—
NYMEX WTI Crude Sold Puts:
Notional volume (Bbl)	8,100,000		7,800,000		600,000		600,000
Weighted average sold put price ($/Bbl)	$	43.08	$	43.27	$	43.00	$	43.00
NYMEX HH Natural Gas Swaps:
Notional volume (MMBtu)	27,000,000		—		—		—
Weighted average fixed price ($/MMBtu)	$	2.75	$	—	$	—	$	—
CIG Basis Gas Swaps:
Notional volume (MMBtu)	34,200,000		2,400,000		—		—
Weighted average fixed basis price ($/MMBtu)	$	(0.61)	$	(0.57)	$	—	$	—

The following tables detail the fair value of the Company’s derivative instruments, including the gross amounts and adjustments made to net the derivative instruments for the presentation in the condensed consolidated balance sheets (in thousands):

	As of March 31, 2020
Location on Balance Sheet	Gross Amounts of Recognized Assets and Liabilities		Gross Amounts Offsets in the Balance Sheet(1)		Net Amounts of Assets and Liabilities Presented in the Balance Sheet		Gross Amounts not Offset in the Balance Sheet(2)		Net Amounts(3)
Current assets	$	293,761	$	(129,431)	$	164,330	$	(716)	$	252,397
Non-current assets	127,705		(38,922)		88,783		—		—
Current liabilities	(130,147)		129,431		(716)		716		—
Non-current liabilities	(38,922)		38,922		—		—		—

	As of December 31, 2019
Location on Balance Sheet	Gross Amounts of Recognized Assets and Liabilities		Gross Amounts Offsets in the Balance Sheet(1)		Net Amounts of Assets and Liabilities Presented in the Balance Sheet		Gross Amounts not Offset in the Balance Sheet(2)		Net Amounts(3)
Current assets	$	48,605	$	(31,051)	$	17,554	$	—	$	30,783
Non-current assets	38,034		(24,805)		13,229		—		—
Current liabilities	(33,049)		31,051		(1,998)		—		(2,106)
Non-current liabilities	(24,913)		24,805		(108)		—		—

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(1)Agreements are in place that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements.

(2)Netting for balance sheet presentation is performed by current and non-current classification. This adjustment represents amounts subject to an enforceable master netting arrangement, which are not netted on the condensed consolidated balance sheets. There are no amounts of related financial collateral received or pledged.

(3)Net amounts are not split by current and non-current. All counterparties in a net asset position are shown in the current asset line, and all counterparties in a net liability position are shown in the current liability line item.

The table below sets forth the commodity derivatives gain (loss) for the three months ended March 31, 2020 and 2019 (in thousands). Commodity derivatives gain (loss) are included under the other income (expense) line item in the condensed consolidated statements of operations.

	For the Three Months Ended March 31,
	2020		2019
Commodity derivatives gain (loss)	$	263,015	$	(122,091)

Note 7—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 period indicated (in thousands):

	For the Three Months Ended March 31, 2020
Balance beginning of period	$	95,908
Liabilities incurred or acquired	192
Liabilities settled	(10,787)
Revisions in estimated cash flows	6,638
Accretion expense	1,822
Balance end of period	$	93,773

Note 8—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:

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•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.

The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2020 and December 31, 2019 by level within the fair value hierarchy (in thousands):

	Fair Value Measurement at March 31, 2020
	Level 1		Level 2		Level 3		Total
Financial Assets:
Commodity derivative assets	$	—	$	253,113	$	—	$	253,113
Financial Liabilities:
Commodity derivative liabilities	$	—	$	716	$	—	$	716

	Fair Value Measurement at December 31, 2019
	Level 1		Level 2		Level 3		Total
Financial Assets:
Commodity derivative assets	$	—	$	30,783	$	—	$	30,783
Financial Liabilities:
Commodity derivative liabilities	$	—	$	2,106	$	—	$	2,106

The following methods and assumptions were used to estimate the fair value of the assets and liabilities in the tables above:

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.

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 amount of the Company’s credit facility approximated fair value as it bears interest at

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variable rates over the term of the loan. The fair values of the 2024 Senior Notes and 2026 Senior Notes were derived from available market data. As such, the Company has classified the 2024 Senior Notes and 2026 Senior Notes as Level 2. Please refer to Note 5—Long-Term Debt for further information. The Company’s policy is to recognize transfers between levels at the end of the period. This disclosure (in thousands) does not impact the Company's financial position, results of operations or cash flows.

	At March 31, 2020						At December 31, 2019
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Credit Facility	$	470,000	$	470,000	$	470,000	$	470,000
2024 Senior Notes(1)	$	395,075	$	68,000	$	394,824	$	250,000
2026 Senior Notes(2)	$	691,272	$	119,032	$	690,953	$	420,113

(1)The carrying amount of the 2024 Senior Notes includes unamortized debt issuance costs of $4.9 million and $5.2 million as of March 31, 2020 and December 31, 2019, respectively.

(2)The carrying amount of the 2026 Senior Notes includes unamortized debt issuance costs of $8.9 million and $9.2 million as of March 31, 2020 and December 31, 2019, respectively.

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 review its proved oil and gas properties for potential impairment when events and circumstances indicate, and at least annually, a possible decline in the recoverability of the carrying value of such property. The Company uses an income approach analysis based on the net discounted future cash flows of producing property. The future cash flows are based on management’s estimates for the future. Unobservable inputs include estimates of oil and gas production, as the case may be, from the Company’s reserve reports, commodity prices based on the sales contract terms and forward price curves, operating and development costs and a discount rate based on a market-based weighted average cost of capital (all of which are Level 3 inputs within the fair value hierarchy). For the three months ended March 31, 2020 and 2019, the Company recognized $0.8 million and $8.2 million, respectively, in impairment expense on its proved oil and gas properties related to impairment of assets in its northern field. The fair value did not exceed the Company's carrying amount associated with its proved oil and gas properties in its northern field.

Note 9—Income Taxes

The Company computes an estimated annual effective tax rate (“AETR”) each quarter based on the current and forecasted operating results. The income tax expense or benefit associated with the interim period is computed using the most recent estimated AETR applied to the year-to-date ordinary income or loss, plus the tax effect of any significant or infrequently occurring items recorded during the interim period. The computation of the estimated AETR at each interim period requires certain estimates and significant judgements including, but not limited to, the expected operating income (loss) for the year, projections of the proportion of income earned and taxed in various jurisdictions, permanent differences and the likelihood of recovering deferred tax assets generated in the current year. The accounting estimates used to compute the provision for income taxes may change as new events occur, more experience is obtained, and additional information becomes known or as the tax environment changes.

The effective combined U.S. federal and state income tax rate for the three months ended March 31, 2020 and 2019 was 19.6% and 23.6%, respectively. The effective rate for the three months ended March 31, 2020 and 2019 differs from the amount that would be provided by applying the statutory U.S. federal income tax rate of 21% to pre-tax income due to (i) the effect of a full valuation allowance in effect at March 31, 2020 and (ii) the effects of state taxes, permanent taxable differences, and income attributable to non-controlling interest for the three months ended March 31, 2019.

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Before accounting for a naked credit deferred tax liability, net tax expense for the three months ended March 31, 2020 was reduced to zero due to the valuation allowance. The naked credit deferred tax liability results in tax expense of $2.2 million for the three months ended March 31, 2020.

The Company considers whether some portion, or all, of the deferred tax assets (“DTAs”) will be realized based on a more likely than not standard of judgment. The ultimate realization of DTAs is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. At December 31, 2019, the Company had a valuation allowance totaling $246.1 million against its DTAs resulting from prior year cumulative financial losses, oil and gas impairments, and significant net operating losses for U.S. federal and state income tax. The Company assesses the appropriateness of its valuation allowance on a quarterly basis. As of March 31, 2020, there was no change in the Company’s assessment of the realizability of its DTAs, except for a naked credit deferred tax liability.

Note 10—Stock-Based Compensation

Extraction Long Term Incentive Plan

In October 2016, the Company’s board of directors adopted the Extraction Oil & Gas, Inc. 2016 Long Term Incentive Plan (the “2016 Plan” or “LTIP”), pursuant to which employees, consultants and directors of the Company and its affiliates performing services for the Company are eligible to receive awards. The 2016 Plan provides 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 Company's 2016 Long Term Incentive Plan. The amended and restated 2016 Long Term Incentive Plan provides a total reserve of 32.2 million shares of common stock for issuance pursuant to awards under the LTIP. Extraction 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.

Restricted Stock Units

Restricted stock units granted under the LTIP (“RSUs”) generally vest 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 LTIP. The Company assumed a forfeiture rate of 0 as part of the grant date estimate of compensation cost.

The Company recorded $0.8 million of stock-based compensation costs related to RSUs for the three months ended March 31, 2020 as compared to $6.9 million for the three months ended March 31, 2019. These costs were included in the condensed consolidated statements of operations within the general and administrative expenses line item. As of March 31, 2020, there was $8.3 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 2.2 years.

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

	Number of Shares	Weighted Average Grant Date Fair Value
Non-vested RSUs at January 1, 2020	2,635,765	$	8.32
Granted	1,252,000	$	0.31
Forfeited	(351,679)	$	9.44
Vested	(356,008)	$	14.23
Non-vested RSUs at March 31, 2020	3,180,078	$	4.38

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Performance Stock Awards

The Company granted performance stock awards ("PSAs") to certain executives under the 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 based 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. A stochastic process is a mathematically defined equation that can create a series of outcomes over time. Those outcomes are not deterministic in nature, which means that by iterating the equations multiple times, different results will be obtained for those iterations. In the case of the Company's PSAs, the Company cannot predict with certainty the path its stock price or the stock prices of its peer will take over the performance period. By using a stochastic simulation, the Company can create multiple prospective stock pathways, statistically analyze these simulations, and ultimately make inferences regarding the most likely path the stock price will take. As such, because future stock prices are stochastic, or probabilistic with some direction in nature, the stochastic method, specifically the Monte Carlo Model, is deemed an appropriate method by which to determine the fair value of the PSAs. 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 Company recorded a credit of $0.8 million of stock-based compensation costs related to PSAs for the three months ended March 31, 2020 as compared to $1.5 million of stock-based compensation costs related to PSAs for the three months ended March 31, 2019. These costs were included in the condensed consolidated statements of operations within the general and administrative expenses line item. As of March 31, 2020, there was $5.2 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 2.3 years.

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

	Number of Shares (1)	Weighted Average Grant Date Fair Value
Non-vested PSAs at January 1, 2020	2,863,190	$	7.72
Granted	5,952,700	$	0.29
Forfeited	—	$	—
Vested	—	$	—
Non-vested PSAs at March 31, 2020	8,815,890	$	2.70

(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.

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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 utilizes the "simplified" method to estimate the expected term of the stock options granted as there is 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 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 0 stock-based compensation costs related to stock options for the three months ended March 31, 2020, as compared to $3.8 million for the three months ended March 31, 2019. These costs were included in the condensed consolidated statements of operations within the general and administrative expenses line item. As of March 31, 2020, there are 0 remaining unrecognized compensation costs related to the stock options granted to certain executives.

There was no stock option activity from January 1, 2020 through March 31, 2020. However, as of March 31, 2020, there was approximately 5.2 million outstanding and exercisable stock options with a weighted-average exercise price of $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 0 as part of the grant date estimate of compensation cost.

The Company recorded 0 stock-based compensation costs related to Incentive RSUs for the three months ended March 31, 2020. The Company recorded $0.8 million of stock-based compensation costs related to Incentive RSUs for the three months ended March 31, 2019. These costs were included in the condensed consolidated statements of operations within the general and administrative expenses line item. As of March 31, 2020, there are no remaining unrecognized compensation costs related to the Incentive RSUs granted to certain employees.

Note 11—Equity

Series A Preferred Stock

The holders of our Series A Preferred Stock (the "Series A Preferred Holders") are entitled to receive a cash dividend of 5.875% per year, payable quarterly in arrears, and we have 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 are partially paid in cash). We have paid the quarterly dividends in kind since the fourth quarter of 2019, and expect to pay future quarterly dividends in kind. The Series A Preferred Stock is 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 IPO, we 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. We can now redeem the Series A Preferred Stock at any time for the liquidation preference, which is $194.7 million. In certain situations, including a change of control, the Series A Preferred Stock may be 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 matures on October

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15, 2021, at which time they are mandatorily redeemable for cash at the liquidation preference to the extent there are legally available funds to do so. For more information, see the Company’s Annual Report.

Elevation Common Units

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 will account for Elevation under the cost method of accounting. The Company reserves all rights related to actions taken by Elevation’s board of managers.

Elevation Preferred Units

In July 2018 and July 2019, respectively, Elevation sold 150,000 and 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 $150.0 million and $100.0 million, respectively. These Preferred Units represent the noncontrolling interest presented on the condensed consolidated balance sheets, condensed consolidated statements of operations and condensed consolidated statements of changes in stockholders' equity and noncontrolling interest. As of March 16, 2020, Elevation is a separate, deconsolidated entity and the assets and credit of Elevation are not available to satisfy the debts and other obligations of the Company or its other subsidiaries. As part of the July 2018 transaction, the Company committed to Elevation that it would drill at least 425 qualifying wells in the acreage dedicated to Elevation by December 31, 2023, subject to reductions if Extraction does not sell the full amount of additional Elevation Preferred Units to the Purchaser. 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 13—Commitments and Contingencies — Elevation Gathering Agreements for further details.

Upon deconsolidation of Elevation Midstream, LLC as discussed in Note 1—Business and Organization, the $270.5 million Elevation preferred unit balance in the noncontrolling interest line item of the condensed 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 condensed consolidated statements of changes in stockholders' equity 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 three months ended March 31, 2020 and 2019, respectively, Elevation recognized $0.6 million and $0.9 million of commitment fees paid-in-kind included under the Preferred Unit commitment fees and dividends paid-in-kind line item in the condensed consolidated statements of changes in stockholders' equity and noncontrolling interest.

The Elevation Preferred Units entitle the Purchaser to receive quarterly dividends at a rate of 8.0% per annum. In respect of quarters ending prior to and including June 30, 2020, the Dividend is payable in cash or in kind at the election of Elevation. After June 30, 2020, the Dividend is payable solely in cash. For the three months ended March 31, 2020 and 2019, respectively, Elevation recognized $5.5 million and $3.1 million of dividends paid-in-kind included under the Preferred Unit commitment fees and dividends paid-in-kind line item in the condensed consolidated statements of changes in stockholders' equity and noncontrolling interest.

Note 12—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 of the Company.

The Company uses the “if-converted” method to determine potential dilutive effects of the Company’s outstanding Series A Preferred Stock and the treasury method to determine the potential dilutive effects of outstanding

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restricted stock awards and stock options. The basic weighted average shares outstanding calculation is based on the actual days in which the shares were outstanding for the three months ended March 31, 2020 and 2019.

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

	For the Three Months Ended March 31,
	2020		2019
Basic and Diluted Income (Loss) Per Share
Net income (loss)	$	9,037	$	(94,032)
Less: Noncontrolling interest	(6,160)		(3,975)
Less: Adjustment to reflect Series A Preferred Stock dividends	(4,748)		(2,721)
Less: Adjustment to reflect accretion of Series A Preferred Stock discount	(1,770)		(1,596)
Adjusted net loss available to common shareholders, basic and diluted	$	(3,641)	$	(102,324)
Denominator:
Weighted average common shares outstanding, basic and diluted (1) (2)	137,726		170,702
Loss Per Common Share
Basic and diluted	$	(0.03)	$	(0.60)

(1)For the three months ended March 31, 2020, 8,339,698 potentially dilutive shares, including restricted stock awards and stock options outstanding, were not included in the calculation above, as they had an anti-dilutive effect on EPS. Additionally, 11,472,445 common shares associated with the assumed conversion of Series A Preferred Stock were also excluded, as they would have had an anti-dilutive effect on EPS.

(2)For the three months ended March 31, 2019, 8,017,004 potentially dilutive shares, including restricted stock awards and stock options outstanding, were not included in the calculation above, as they had an anti-dilutive effect on EPS. Additionally, 11,472,445 common shares associated with the assumed conversion of Series A Preferred Stock were also excluded, as they would have had an anti-dilutive effect on EPS.

Note 13—Commitments and Contingencies

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. Maturities of operating lease liabilities associated with right-of-use assets and including imputed interest were as follows (in thousands):

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	As of March 31, 2020			As of December 31, 2019
2020 - remaining	13,653		2020	19,040
2021	5,247		2021	5,247
2022	2,211		2022	2,211
2023	2,246		2023	2,246
2024	2,301		2024	2,301
Thereafter	8,273		Thereafter	8,273
Total lease payments	33,931		Total lease payments	39,318
Less imputed interest (1)	(4,264)		Less imputed interest (1)	(4,735)
Present value of lease liabilities (2)	$	29,667	Present value of lease liabilities (2)	$	34,583

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

(2) Of the total present value of lease liabilities as of March 31, 2020 and December 31, 2019, $15.2 million and $17.4 thousand, respectively, were recorded in accounts payable and accrued liabilities and $14.5 million and $17.2 thousand, respectively, were recorded in other non-current liabilities on the condensed consolidated balance sheets.

Drilling Rigs

As of March 31, 2020, the Company was subject to commitments on 2 drilling rigs contracted through May 2020 and February 2021. These costs are capitalized within proved oil and gas properties on the condensed consolidated balance sheets and are included as short-term lease costs. In the event of early termination of these contracts, the Company would be obligated to pay an aggregate amount of approximately $9.0 million as of March 31, 2020, as required under the terms of the contracts. Subsequent to March 31, 2020, the Company renegotiated the terms of the drilling rig contracts. After the modifications, in the event of early termination, the Company would be obligated to pay an aggregate amount of approximately $8.0 million as of May 6, 2020.

Delivery Commitments

As of March 31, 2020, the Company’s oil marketer is subject to a firm transportation agreement that commenced in November 2016 and has 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. In May 2017, the Company amended its agreement with its oil marketer that requires it to sell all of its crude oil from an area of mutual interest in exchange for a make-whole provision that allows the Company to satisfy any minimum volume commitment deficiencies incurred by its oil marketer with future barrels of crude oil in excess of their minimum volume commitment during the contract term. In May 2019, the Company extended the term of this agreement through October 31, 2020 subject to an evergreen provision thereafter where either party can provide a six month notice of termination beginning November 1, 2020. Due to the contract termination date, the amount of consideration recognized in revenue is reduced. Please see Note 2—Basis of Presentation, Significant Accounting Policies and Recent Accounting Pronouncements — Revenue — Contract Balances. The Company has posted a letter of credit for this agreement in the amount of $40.0 million. The Company may be required to pay a shortfall fee for any volume deficiencies under these commitments. The aggregate remaining amount of estimated payments under these agreements is approximately $655.8 million.

The Company has 2 long-term crude oil gathering commitments with a unconsolidated subsidiary, in which the Company had a minority ownership interest. Please see Note 1—Business and Organization for information related to the deconsolidation of Elevation Midstream, LLC. The first agreement commenced in November 2016 and has 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 Company may be required to pay a shortfall fee for any volume deficiencies under this commitment. The second agreement commenced in July 2019 and has 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 may be

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required to pay a shortfall fee for any volume deficiencies under this commitment. The aggregate remaining amount of estimated payments under these agreements is approximately $117.7 million.

In February 2019, the Company entered into two long-term gas gathering and processing agreements with third-party midstream providers. One of the agreements additionally includes a long-term NGL sales commitment for take-in-kind NGLs from other processing agreements. The first agreement commenced in November 2019 and has 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 are 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. The aggregate remaining amount of estimated payments under this agreement is approximately $299.3 million. The second agreement commenced on January 2020 and has a term of ten years with an annual minimum volume commitment of 13.0 Bcf in years one through ten. The second agreement also includes a commitment to sell take-in-kind NGLs 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. The Company may be required to pay a shortfall fee for any volume deficiencies under these commitments, calculated based on the applicable gathering and processing fees and/or, with respect to the NGL commitment, the NGL transport cost. Under its current drilling plans, the Company expects to meet these volume commitments.

The summary of these minimum volume commitments as of March 31, 2020, was as follows:

	Oil (MBbl)	Gas (MMcf)	Total (MBOE)
2020 - remaining	6,492	25,815	10,794
2021	9,797	46,540	17,554
2022	8,944	49,758	17,237
2023	9,490	41,850	16,465
2024	9,516	34,160	15,209
Thereafter	29,860	40,260	36,570
Total	74,099	238,383	113,829

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 includes 2 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 deficiency 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 3 long-term contracts to supply 125,000 dekatherms of residue gas per day for five years to a transportation company. While our production is expected to satisfy these contracts, the aggregate remaining amount of estimated commitment assuming no production is $31.0 million. The Company has posted a letter of credit for this agreement in the amount of $8.7 million.

The aggregate remaining amount of estimated remaining payments under these agreements is $1,103.8 million.

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Elevation Gathering Agreements

In November 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. Elevation has alleged that if the Company fails to complete the wells by the commitment 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, the drilling commitment now consists of 297 wells in the Broomfield area of operations.

In April 2019, the Elevation Gathering Agreements were amended to provide for, among other amendments, the inclusion of additional gathering facilities in Elevation’s Badger facility. Pursuant to this amendment, Elevation has asserted that the additional gathering facilities were required to be completed by April 1, 2020 or, within 30 days of such date, Elevation could assert that 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. As of March 31, 2020, the costs incurred by Elevation for these additional gathering facilities totaled $34.7 million. The Company did not complete these additional gathering facilities by April 1, 2020, and Elevation has alleged that Extraction is in breach of the 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. While the Company disputes that these amounts are due to Elevation, under ASC Topic 450 - Contingencies, the Company recorded the amount in accounts payable and accrued liabilities, related party on the condensed consolidated balance sheet as of March 31, 2020 and in other operating expenses on the condensed consolidated statements of operations.

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 $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 does not expect to incur additional Connect Fees for the year ending December 31, 2020.

In March 2020, the Elevation Gathering Agreements were further amended to reset all gathering rates and eliminate existing minimum drilling commitment. This amendment will not become effective until after all Elevation Preferred Units have been redeemed in full or are otherwise no longer outstanding.

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 in the condensed consolidated balance sheets 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 natural gas and oil 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 March 31, 2020 which have not been provided for or would otherwise have a material impact on our 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. Accrued environmental liabilities are recorded in accounts payable and accrued liabilities on the condensed consolidated balance sheets. The liability ultimately incurred with respect to a matter may exceed the related accrual.

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COGCC Notices of Alleged Violations (“NOAVs”). The Company has received NOAVs from the COGCC for alleged compliance violations that the Company has responded to. At this time, the COGCC has not alleged any specific penalty amounts in these matters. The Company does not believe that any penalties that could result from these NOAVs will have a material effect on our business, financial condition, results of operations or liquidity, but they may exceed $100,000.

Midstream Connections. The Company had dedicated the production from some acreage to a certain midstream service provider. However, the Company was unable to connect well pads to the provider due to the inability to secure right of way access for building the connection pipeline. Because the acreage’s production was dedicated to the midstream provider, they have invoiced the Company for oil and gas handled by other midstream providers. The Company disputes these invoices based on force majeure and may have other contractual or legal defenses. The Company’s maximum exposure as of March 31, 2020 was $15.7 million. As of March 31, 2020, no contingent liability has been recorded as the amount of the loss cannot be reasonably estimated.

Elevation Matador Facility. Under the Elevation LLC Agreement, the Company is required to complete the gathering facilities in Elevation’s Matador facility servicing the Company’s Hawkeye area by August 1, 2020. As part of the Company’s abandonment of further developing this Matador gathering system and facilities that were being constructed, Elevation has alleged that Extraction will be required to reimburse Elevation for all such expenditures on this project. Elevation is currently disputing certain costs related to this project with a third-party contractor that was working on the project. The Company’s maximum exposure as of March 31, 2020 was $20.7 million. As of March 31, 2020, no contingent liability has been recorded as the amount of the loss cannot be reasonably estimated.

Elevation Gathering. As discussed above under 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. While the Company disputes that these amounts are due to Elevation, under ASC Topic 450 - Contingencies, the Company recorded the amount in accounts payable and accrued liabilities, related party on the condensed consolidated balance sheet as of March 31, 2020 and in other operating expenses on the condensed consolidated statements of operations.

Note 14—Related Party Transactions

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 holders of the 2026 Senior Notes are also 5% stockholders of the Company. 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.

Elevation Midstream, LLC

As discussed in Note 13—Commitments and Contingencies, 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. While the Company disputes that these amounts are due to Elevation, under ASC Topic 450 - Contingencies, the Company recorded the amount in accounts payable and accrued liabilities, related party on the condensed consolidated balance sheet as of March 31, 2020 and in other operating expenses on the condensed consolidated statements of operations.

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Note 15—Segment Information

Beginning in the fourth quarter of 2018, the Company had 2 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 three months ending March 31, 2019, the Company’s gathering and facilities segment was in the construction phase and no revenue generating activities had commenced. 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 segment disclosures include the gathering and facilities segment because it was consolidated through March 16, 2020. Please see Note 1—Business and Organization for further information related to the deconsolidation of Elevation Midstream, LLC. After March 31, 2020, Extraction will report as a single operating segment.

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

	For the Three Months Ended March 31,
	2020		2019
Reconciliation of Adjusted EBITDAX to Income (Loss) Before Income Taxes
Exploration and production segment EBITDAX	$	122,639	$	138,339
Gathering and facilities segment EBITDAX	1,256		(152)
Subtotal of Reportable Segments	$	123,895	$	138,187
Less:
Depletion, depreciation, amortization and accretion	$	(76,051)	$	(118,770)
Impairment of long lived assets	(775)		(8,248)
Other operating expenses	(52,575)		—
Exploration and abandonment expenses	(112,480)		(6,194)
Gain on sale of property and equipment	—		222
Gain (loss) on commodity derivatives	263,015		(122,091)
Settlements on commodity derivative instruments	(39,295)		10,329
Premiums paid for derivatives that settled during the period	—		9,549
Stock-based compensation expense	—		(13,008)
Amortization of debt issuance costs	(1,242)		(1,497)
Gain on repurchase of 2026 Senior Notes	—		7,317
Interest expense	(20,116)		(18,828)
Loss on deconsolidation of Elevation Midstream, LLC	(73,139)		—
Income (Loss) Before Income Taxes	$	11,237	$	(123,032)

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Financial information of the Company's reportable segments was as follows for the three months ended March 31, 2020 and 2019 (in thousands).

	For the Three Months Ended March 31, 2020
	Exploration and Production		Gathering and Facilities		Elimination of Intersegment Transactions		Consolidated Total
Revenues:
Revenues from third parties	$	163,714	$	1,473	$	—	$	165,187
Revenues from Extraction	—		4,513		(4,513)		—
Total Revenues	$	163,714	$	5,986	$	(4,513)	$	165,187
Operating Expenses and Other Income (Expense):
Direct operating expenses	$	(70,924)	$	(3,935)	$	4,294	$	(70,565)
Depletion, depreciation, amortization and accretion	(74,952)		(1,099)		—		(76,051)
Interest income	61		29		—		90
Interest expense	(21,358)		—		—		(21,358)
Earnings in unconsolidated subsidiaries	—		480		—		480
Subtotal Operating Expenses and Other Income (Expense):	$	(167,173)	$	(4,525)	$	4,294	$	(167,404)
Segment Assets	$	2,703,388	$	—	$	—	$	2,703,388
Capital Expenditures	155,441		(6,311)		—		149,130
Investment in Equity Method Investees	—		—		—		—
Segment EBITDAX	122,639		1,256		—		123,895

	For the Three Months Ended March 31, 2019
	Exploration and Production		Gathering and Facilities		Elimination of Intersegment Transactions		Consolidated Total
Revenues:
Revenues from third parties	$	221,917	$	—	$	—	$	221,917
Revenues from Extraction	—		—		—		—
Total Revenues	$	221,917	$	—	$	—	$	221,917
Operating Expenses and Other Income (Expense):
Direct operating expenses	$	—	$	—	$	—	$	—
Depletion, depreciation, amortization and accretion	(118,751)		(19)		—		(118,770)
Interest income	154		625		—		779
Interest expense	(13,008)		—		—		(13,008)
Earnings in unconsolidated subsidiaries	—		338		—		338
Subtotal Operating Expenses and Other Income (Expense):	$	(131,605)	$	944	$	—	$	(130,661)
Segment Assets	$	3,813,513	$	284,200	$	(714)	$	4,096,999
Capital Expenditures	158,622		58,863		—		217,485
Investment in Equity Method Investees	—		17,555		—		17,555
Segment EBITDAX	138,339		(152)		—		138,187

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q (“Quarterly Report”) contains "forward-looking statements." All statements, other than statements of historical facts, included or incorporated by reference herein concerning, among other things, planned capital expenditures, increases in oil and gas production, the number of anticipated wells to be drilled or completed after the date hereof, future cash flows and borrowings, pursuit of potential acquisition opportunities, our financial position, business strategy and other plans and objectives for future operations, are forward-looking statements. These forward-looking statements are identified by their use of terms and phrases such as ''may," "expect," "estimate," "project," "plan," "believe," "intend," "achievable," "anticipate," ''will," "continue," ''potential," "should," "could," and similar terms and phrases. For such statements, we claim the protection of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties. Our results could differ materially from those anticipated in these forward-looking statements as a result of certain factors, including, among others:

•our ability to meet the financial covenants in our debt agreements and continue as a going concern;

•the success of our ongoing efforts to develop and implement a restructuring of our capital structure;

•federal and state regulations and laws;

•capital requirements and uncertainty of obtaining additional funding on terms acceptable to us;

•risks and restrictions related to our debt agreements;

•our ability to use derivative instruments to manage commodity price risk;

•realized oil, natural gas and NGL prices;

•a decline in oil, natural gas and NGL production, and the impact of general economic conditions on the demand for oil, natural gas and NGL and the availability of capital to oil and natural gas producers;

•asset impairments from commodity price declines;

•the outbreak of communicable diseases such as coronavirus;

•the willingness of the Organization of Petroleum Exporting Countries (“OPEC”) and certain other oil and natural gas producing countries to set and maintain production levels;

•unsuccessful drilling and completion activities and the possibility of resulting write-downs;

•geographical concentration of our operations;

•constraints in the DJ Basin of Colorado with respect to gathering, transportation and processing facilities and marketing;

•lack of U.S. domestic storage;

•our ability to meet our proposed drilling schedule and to successfully drill wells that produce oil or natural gas in commercially viable quantities;

•shortages of oilfield equipment, supplies, services and qualified personnel and increased costs for such equipment, supplies, services and personnel;

•adverse variations from estimates of reserves, production, production prices and expenditure requirements, and our inability to replace our reserves through exploration and development activities;

•incorrect estimates associated with properties we acquire relating to estimated proved reserves, the presence or recoverability of estimated oil and natural gas reserves and the actual future production rates and associated costs of such acquired properties;

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•drilling operations associated with the employment of horizontal drilling techniques, and adverse weather and environmental conditions;

•limited control over non-operated properties;

•title defects to our properties and inability to retain our leases;

•our ability to successfully develop our large inventory of undeveloped operated and non-operated acreage;

•our ability to retain key members of our senior management and key technical employees;

•risks relating to managing our growth, particularly in connection with the integration of significant acquisitions;

•impact of environmental, health and safety, and other governmental regulations, and of current or pending legislation;

•risks associated with a material weakness in our internal control over financial reporting;

•changes in tax laws;

•effects of competition; and

•seasonal weather conditions.

Reserve engineering is a process of estimating underground accumulations of oil, natural gas, and NGL that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers and management. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil, natural gas and NGL that are ultimately recovered.

In addition to the other information and risk factors set forth in this Quarterly Report, you should carefully consider the risk factors and other cautionary statements described under the heading “Risk Factors” included in our Annual Report on Form 10-K for the year ended December 31, 2019 (our “Annual Report”) and in our other filings with the Securities and Exchange Commission, which could materially affect our business, financial condition or future results. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results. Other than as set forth in this Quarterly Report, there have been no material changes in our risk factors from those described in our Annual Report.

All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements in this section and elsewhere in this Quarterly Report. Except as required by law, we do not assume a duty to update these forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise.

Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) is intended to provide the reader of the financial statements with a narrative from the perspective of management on the financial condition, results of operations, liquidity and certain other factors that may affect the Company’s operating results. MD&A should be read in conjunction with the Condensed Consolidated Financial Statements and related Notes included in Part I, Item 1 of this Quarterly Report. The following information updates the discussion of the Company’s financial condition provided in our Annual Report and analyzes the changes in the results of operations between the three months ended March 31, 2020 and 2019.

EXECUTIVE SUMMARY

We are an independent oil and gas company focused on the acquisition, development and production of oil, natural gas and NGL reserves, as well as the construction and support of midstream assets to gather and process crude oil and gas production in the Rocky Mountain region, primarily in the Wattenberg Field of the Denver-Julesburg Basin of Colorado. We have developed an oil, natural gas and NGL asset base of proved reserves, as well as a portfolio of development drilling opportunities on high resource-potential leasehold on contiguous acreage blocks in some of the

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most productive areas of what we consider to be the core of the DJ Basin. We are focused on improving cash flow and our liquidity while reducing debt.

Financial Results

For the three months ended March 31, 2020, crude oil, natural gas and NGL sales, coupled with the impact of settled derivatives, increased to $204.5 million as compared to $202.0 million in the same prior year period due to an increase in sales volumes of approximately 1,341 MBoe, partially offset by a decrease of $4.25 in realized price per BOE, including settled derivatives.

For the three months ended March 31, 2020, we had net income of $9.0 million as compared to a net loss of $94.0 million for the three months ended March 31, 2019. The change to net income for the three months ended March 31, 2020 from net loss for the three months ended March 31, 2019 was primarily driven by an increase in commodity derivative gain of $385.1 million, partially offset by an increase in operating expenses of $112.0 million and a decrease in sales revenue of $56.7 million.

Adjusted EBITDAX was $123.9 million for the three months ended March 31, 2020 as compared to $138.2 million for the three months ended March 31, 2019, reflecting a 10.3% decrease. Adjusted EBITDAX is a non-GAAP financial measure. For a definition of Adjusted EBITDAX and a reconciliation to our most directly comparable financial measure calculated and presented in accordance with GAAP, please read “—Adjusted EBITDAX.”

Operational Results

During the three months ended March 31, 2020, we focused on improving free cash flow and implemented operational efficiencies to reduce drilling and completion costs. We incurred approximately $146.6 million in drilling 34 gross (24.5 net) wells with an average lateral length of 2.3 miles and completing 28 gross (22.7 net) wells with an average lateral length of 2.3 miles, all of which were horizontal wells in the DJ Basin. In addition, we incurred approximately $8.8 million of leasehold and surface acreage additions.

Recent Developments

COVID-19 Outbreak and Global Industry Downturn

The recent worldwide outbreak in several countries, including the United States, of a highly transmissible and pathogenic coronavirus (“COVID-19”) and the uncertainty regarding the impact of COVID-19 and various governmental actions taken to mitigate the impact of COVID-19 have resulted in an unprecedented decline in demand for oil and natural gas. At the same time, the decision by Saudi Arabia in March 2020 to drastically reduce export prices and increase oil production followed by curtailment agreements among OPEC and other countries such as Russia further increased uncertainty and volatility around global oil supply-demand dynamics. Decreased demand from much of the United States being on lockdown to prevent the spread of COVID-19 caused domestic storage capacity to begin to fill up during March and April causing further price declines and ultimately causing oil prices to plummet. We expect the excess supply of oil and natural gas in the United States to continue for a sustained period.

The COVID-19 outbreak and its development into a pandemic in March 2020 have required that we take precautionary measures intended to help minimize the risk to our business, employees, customers, suppliers and the communities in which we operate. Our operational employees are currently still able to work on site. However, we have taken various precautionary measures with respect to such operational employees such as requiring them to verify they have not experienced any symptoms consistent with COVID-19, or been in close contact with someone showing such symptoms, before reporting to the work site, quarantining any operational employees who have shown signs of COVID-19 (regardless of whether such employee has been confirmed to be infected) and imposing social distancing requirements on work sites, all in accordance with the guidelines released by the Center for Disease Control. In addition, most of our non-operational employees are now working remotely. We have not yet experienced any material operational disruptions (including disruptions from our suppliers and service providers) as a result of the COVID-19 outbreak, nor have we had any confirmed cases of COVID-19 on any of our work sites.

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Due to the decline in crude oil prices and ongoing uncertainty regarding the oil supply-demand macro environment, we have recently reduced our operations in order to preserve capital. Specifically, we have renegotiated the terms of our drilling rig contracts as discussed in Note 13—Commitments and Contingencies in Part I, Item 1. Financial Information of this Quarterly Report.

In addition, given the weakness in realized oil prices, we are actively evaluating whether to voluntarily curtail or shut-in a substantial portion of our current production volumes and will continue to evaluate such a measure on a regular basis in response to market conditions and contractual obligations. As substantially all of our revenues are generated by the production and sale of hydrocarbons, the curtailment or shut-in of our production could adversely affect our business, financial condition, results of operations, liquidity, and ability to finance planned capital expenditures.

Please also see Part II, Item 1A in our Annual Report and in this Quarterly Report for further information related to these matters.

Deconsolidation of Elevation Midstream, LLC

Please see Note 1—Business and Organization in Part I, Item 1. Financial Information of this Quarterly Report for information related to the deconsolidation of Elevation Midstream, LLC.

Reduction in Workforce

We recorded involuntary termination charges of $5.8 million in the first quarter of 2020 primarily related to one-time involuntary termination benefits, office closure and relocation benefits communicated to our workforce in February 2020. This plan was initiated to align the size and composition of our workforce with our expected future operating and capital plans.

February 2020 Divestiture

In February 2020, we 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. We continue to explore divestitures as part of our ongoing initiative to divest non-strategic assets.

Elevation Common Units

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 our ownership of Elevation to be diluted to less than 0.01%. As a result of the Capital Raise, beginning in May 2020 Extraction will account for Elevation under the cost method of accounting. We reserve all rights related to actions taken by Elevation’s board of managers.

Midstream Projects

Primarily due to the significant decrease in oil and gas prices during March 2020, Elevation postponed indefinitely further development of gathering systems and facilities that were to be constructed to service our acreage in Hawkeye and another project in the Southwest Wattenberg area.

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Senate Bill 19-181 "Protect Public Welfare Oil and Gas Operations"

In April 2019, Senate Bill 19-181 ("SB181") became law, increasing the regulatory authority of local governments in Colorado over the surface impacts of oil and gas development in a reasonable manner, and in December 2019, Colorado's Air Quality Control Commission ("AQCC") adopted new rules targeting air emissions from upstream oil and gas operation. Among other things, SB181 (i) repeals a prior law restricting local government land use authority over oil and gas mineral extraction areas to areas designated by the COGCC, (ii) directs the AQCC to review its leak detection and repair rules and to adopt rules to minimize emissions of certain air pollutants, (iii) clarifies that local governments have authority to regulate the siting of oil and gas locations in a reasonable manner, including the ability to inspect oil and gas facilities, impose fines for leaks, spills, and emissions, and impose fees on operators or owners to cover regulation and enforcement costs, (iv) allows local governments or oil and gas operators to request a technical review board to evaluate the effect of the local government’s preliminary or final determination on the operator’s application, (v) repeals an exemption for oil and gas production from counties’ authority to regulate noise, (vi) alters forced pooling requirements by increasing the threshold to compel non-consenting individuals into statutory pooling agreements and (vii) elevates the protection of public health, safety, and welfare, the environment, and wildlife resources in the regulation of oil and gas development. Although industry trade associations opposed SB181, management believes that Extraction can continue to successfully operate our business. However, the enactment of SB181 and the development and implementation of related rules and regulations, which is under way, could lead to delays and additional costs to our business. For example, COGCC rulemaking on flowline safety (completed on November 21, 2019) and the Colorado AQCC and Air Pollution Control Division (“APCD”) rulemaking on air quality standards (completed December 20, 2019) – both pursuant to SB181 – could lead to such delays or costs. Certain interest groups in Colorado opposed to oil and natural gas development generally, and hydraulic fracturing in particular, have advanced various alternatives for ballot initiatives which would result in significantly limiting or preventing oil and natural gas development in the state. Proponents of such initiatives have begun the process of attempting to qualify several initiatives to appear on the ballot in November 2020.

Going Concern

Please see Note 4—Going Concern in Part I, Item 1. Financial Information and “Risk Factors” in Part II, Item 1A of this Quarterly Report, as well as “—Liquidity and Capital Resources” below.

How We Evaluate Our Operations

We use a variety of financial and operational metrics to assess the performance of our oil and gas operations, including:

•Sources of revenue;

•Sales volumes;

•Realized prices on the sale of oil, natural gas and NGL, including the effect of our commodity derivative contracts;

•Lease operating expenses (“LOE”);

•Capital expenditures;

•Adjusted EBITDAX (a Non-GAAP measure); and

•Free cash flow (a Non-GAAP measure).

Sources of Revenues

Our revenues are derived from the sale of our oil and natural gas production, as well as the sale of NGLs that are extracted from our natural gas during processing. Our oil, natural gas and NGL revenues do not include the effects of derivatives. For the three months ended March 31, 2020, our revenues were derived 75% from oil sales, 14% from natural gas sales and 11% from NGL sales. For the three months ended March 31, 2019, our revenues were derived 75% from oil sales, 16% from natural gas sales and 9% from NGL sales. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.

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Sales Volumes

The following table presents historical sales volumes for the periods indicated:

	For the Three Months Ended
	March 31,
	2020	2019
Oil (MBbl)	3,504	3,583
Natural gas (MMcf)	19,003	13,959
NGL (MBbl)	1,906	1,327
Total (MBoe)	8,576	7,236
Average net sales (BOE/d)	94,247	80,401

As reservoir pressures decline, production from a given well or formation decreases. Growth in our future production and reserves will depend on our ability to continue to add or develop proved reserves in excess of our production. Our ability to add reserves through development projects and acquisitions is dependent on many factors, including takeaway capacity in our areas of operation and our ability to raise capital, obtain regulatory approvals, procure contract drilling rigs and personnel and successfully identify and consummate acquisitions. Please read “Risks Related to the Oil, Natural Gas and NGL Industry and Our Business” in Item 1A. of our Annual Report for a further description of the risks that affect us.

Realized Prices on the Sale of Oil, Natural Gas and NGL

Our results of operations depend upon many factors, particularly the price of oil, natural gas and NGL and our ability to market our production effectively. Oil, natural gas and NGL prices are among the most volatile of all commodity prices. For example, during the period from January 1, 2014 to March 31, 2020, NYMEX West Texas Intermediate oil prices ranged from a high of $107.26 per Bbl to a low of $20.09 per Bbl. Average daily prices for NYMEX Henry Hub gas ranged from a high of $6.15 per MMBtu to a low of $1.60 per MMBtu during the same period. Declines in, and continued depression of, the price of oil and natural gas occurring during 2015, 2019 and 2020 are due to a combination of factors including increased U.S. supply, global economic concerns stemming from COVID-19 and the price war between Russia and Saudi Arabia. These price variations can have a material impact on our financial results and capital expenditures.

Oil pricing is predominantly driven by the physical market, supply and demand, financial markets and national and international politics. The NYMEX WTI futures price is a widely used benchmark in the pricing of domestic and imported oil in the United States. The actual prices realized from the sale of oil differ from the quoted NYMEX WTI price as a result of quality and location differentials. In the DJ Basin, oil is sold under various purchase contracts with monthly pricing provisions based on NYMEX pricing, adjusted for differentials.

Natural gas prices vary by region and locality, depending upon the distance to markets, availability of pipeline capacity and supply and demand relationships in that region or locality. The NYMEX Henry Hub price of natural gas is a widely used benchmark for the pricing of natural gas in the United States. Similar to oil, the actual prices realized from the sale of natural gas differ from the quoted NYMEX Henry Hub price as a result of quality and location differentials. For example, wet natural gas with a high Btu content sells at a premium to low Btu content dry natural gas because it yields a greater quantity of NGL. Location differentials to NYMEX Henry Hub prices result from variances in transportation costs based on the natural gas’ proximity to the major consuming markets to which it is ultimately delivered. Also affecting the differential is the processing fee deduction retained by the natural gas processing plant, generally in the form of percentage of proceeds. The price we receive for our natural gas produced in the DJ Basin is based on CIG prices, adjusted for certain deductions.

Our price for NGL produced in the DJ Basin is based on a combination of prices from the Conway hub in Kansas and Mont Belvieu in Texas where this production is marketed.

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The following table provides the high and low prices for NYMEX WTI and NYMEX Henry Hub prompt month contract prices and our differential to the average of those benchmark prices for the periods indicated. The differential varies, but our oil, natural gas and NGL normally sells at a discount to the NYMEX WTI and NYMEX Henry Hub price, as applicable.

	For the Three Months Ended
	March 31,
	2020			2019
Oil
NYMEX WTI High ($/Bbl)	$	63.27		$	60.14
NYMEX WTI Low ($/Bbl)	$	20.09		$	46.54
NYMEX WTI Average ($/Bbl)	$	45.78		$	54.90
Average Realized Price ($/Bbl)(1)	$	35.45		$	46.17
Average Realized Price, with derivative settlements ($/Bbl)(1)	$	45.50		$	41.89
Average Realized Price as a % of Average NYMEX WTI	77.4		%	84.1		%
Differential ($/Bbl) to Average NYMEX WTI(2)	$	(7.91)		$	(8.73)
Natural Gas
NYMEX Henry Hub High ($/MMBtu)	$	2.20		$	3.59
NYMEX Henry Hub Low ($/MMBtu)	$	1.60		$	2.55
NYMEX Henry Hub Average ($/MMBtu)	$	1.87		$	2.87
NYMEX Henry Hub Average converted to a $/Mcf basis(3)	$	2.06		$	3.16
Average Realized Price ($/Mcf)	$	1.17		$	2.57
Average Realized Price, with derivative settlements ($/Mcf)	$	1.39		$	2.25
Average Realized Price as a % of Average NYMEX Henry Hub(3)	56.8		%	81.3		%
Differential ($/Mcf) to Average NYMEX Henry Hub(3)	$	(0.89)		$	(0.59)
NGL
Average Realized Price ($/Bbl)(4)	$	9.02		$	15.53
Average Realized Price as a % of Average NYMEX WTI	19.7		%	28.3		%
BOE
Average Realized Price per BOE	$	19.09		$	30.67
Average Realized Price per BOE with derivative settlements	$	23.67		$	27.92

(1)Includes non-cash amounts allocated to a satisfied performance obligation, recognized within oil sales for the three months ended March 31, 2020, pursuant to ASC 606, Revenue Recognition.

(2)Excludes non-cash amounts allocated to a satisfied performance obligation, recognized within oil sales for the three months ended March 31, 2020, pursuant to ASC 606, Revenue Recognition.

(3)Based on the difference between our average realized price and the NYMEX Henry Hub Average as converted into Mcf using a conversion factor of 1.1 to 1.

(4)The decrease year over year is primarily due to capacity constraints in transporting the wet gas associated with our production coupled with negative market conditions surrounding limited export capacity.

Derivative Arrangements

To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in commodity prices, from time to time, we enter into derivative arrangements for our oil and natural gas production. By removing a significant portion of price volatility associated with our oil and natural gas production, we believe we will mitigate, but not eliminate, the potential negative effects of reductions in oil and natural gas prices on our cash flow from operations for those periods. However, in a portion of our current positions, our hedging activity may also reduce our ability to benefit from increases in oil and natural gas prices. We will sustain losses to the extent our derivatives contract prices are lower than market prices and, conversely, we will realize gains to the extent our derivatives contract prices are higher than market prices. In certain circumstances, where we have unrealized gains in our derivative portfolio, we may choose to restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of our existing positions. See “—Quantitative and Qualitative Disclosure About Market Risk—Commodity Price Risk” for information regarding our exposure to market risk, including the effects of changes in commodity prices, and our commodity derivative contracts.

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We will continue to use commodity derivative instruments to hedge our price risk in the future. Our hedging strategy and future hedging transactions will be determined at our discretion and may be different than what we have done on a historical basis. As a result of recent volatility in the price of oil and natural gas, we have relied on a variety of hedging strategies and instruments to hedge our future price risk. We have utilized swaps, put options and call options, which in some instances require the payment of a premium, to reduce the effect of price changes on a portion of our future oil and natural gas production. We expect to continue to use a variety of hedging strategies and instruments for the foreseeable future.

A swap has an established fixed price. When the settlement price is below the fixed price, the counterparty pays us an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is above the fixed price, we pay our counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume.

A put option has an established floor price. The buyer of the put option pays the seller a premium to enter into the put option. When the settlement price is below the floor price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is above the floor price, the put option expires worthless. Some of our purchased put options have deferred premiums. For the deferred premium puts, we agreed to pay a premium to the counterparty at the time of settlement.

A call option has an established ceiling price. The buyer of the call option pays the seller a premium to enter into the call option. When the settlement price is above the ceiling price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is below the ceiling price, the call option expires worthless.

We combine swaps, purchased put options, sold put options, and sold call options in order to achieve various hedging strategies. Some examples of our 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. We have historically relied on commodity derivative contracts to mitigate our exposure to lower commodity prices.

We have historically been able to hedge our oil and natural gas production at prices that are significantly higher than current strip prices. However, in the current commodity price environment, our ability to enter into comparable derivative arrangements at favorable prices may be limited, and, we are not obligated to hedge a specific portion of our oil or natural gas production.

For a description of our derivative instruments that we utilize and a summary of our commodity derivative contracts as of March 31, 2020, please see Note 6—Commodity Derivative Instruments in Part I, Item 1. Financial Information of this Quarterly Report.

The following table summarizes our historical derivative positions and the settlement amounts for each of the periods indicated.

	For the Three Months Ended
	March 31,
	2020		2019
NYMEX WTI Crude Swaps:
Notional volume (Bbl)	225,000		1,350,000
Weighted average fixed price ($/Bbl)	$	60.13	$	54.58
NYMEX WTI Crude Purchased Puts:
Notional volume (Bbl)	3,650,000		4,725,000
Weighted average purchased put price ($/Bbl)	$	54.79	$	46.05
NYMEX WTI Crude Purchased Calls:
Notional volume (Bbl)	600,000		5,100,000
Weighted average purchased call price ($/Bbl)	$	68.05	$	63.40
NYMEX WTI Crude Sold Calls:
Notional volume (Bbl)	3,650,000		6,600,000

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Weighted average sold call price ($/Bbl)	$	63.34	$	62.17
NYMEX WTI Crude Sold Puts:
Notional volume (Bbl)	3,700,000		4,200,000
Weighted average sold put price ($/Bbl)	$	44.01	$	43.35
NYMEX HH Natural Gas Swaps:
Notional volume (MMBtu)	8,400,000		5,400,000
Weighted average fixed price ($/MMBtu)	$	2.76	$	3.11
NYMEX HH Natural Gas Purchased Puts:
Notional volume (MMBtu)	600,000		3,600,000
Weighted average purchased put price ($/MMBtu)	$	2.90	$	3.04
NYMEX HH Natural Gas Sold Calls:
Notional volume (MMBtu)	600,000		3,600,000
Weighted average sold call price ($/MMBtu)	$	3.48	$	3.46
NYMEX HH Natural Gas Sold Puts:
Notional volume (MMBtu)	—		3,000,000
Weighted average sold put price ($/MMBtu)	$	—	$	2.50
CIG Basis Gas Swaps:
Notional volume (MMBtu)	11,400,000		9,400,000
Weighted average fixed basis price ($/MMBtu)	$	(0.61)	$	(0.75)
Total Amounts Received/(Paid) from Settlement (in thousands)	$	39,295	$	(10,329)
Cash provided by changes in Accounts Receivable and Accounts Payable related to Commodity Derivatives	$	(14,363)	$	6,791
Cash Settlements on Commodity Derivatives per Condensed Consolidated Statements of Cash Flows	$	24,932	$	(3,538)

Lease Operating Expenses

All direct and allocated indirect costs of lifting hydrocarbons from a producing formation to the surface constitutes part of the current operating expenses of a working interest. Such costs include labor, superintendence, supplies, repairs, maintenance, water injection and disposal costs, allocated overhead charges, workover, insurance and other expenses incidental to production, but exclude lease acquisition or drilling or completion expenses.

Capital Expenditures

For the three months ended March 31, 2020, we incurred approximately $146.6 million in drilling and completion capital expenditures. For the three months ended March 31, 2020, we drilled 34 gross (24.5 net) wells with an average lateral length of approximately 2.3 miles and completed 28 gross (22.7 net) wells with an average lateral length of approximately 2.3 miles. We turned to sales 13 gross (12 net) wells with an average lateral length of approximately 2.1 miles. In addition, we incurred approximately $8.8 million of leasehold and surface acreage additions.

The amount and timing of these capital expenditures is within our control and subject to our management’s discretion. We retain the flexibility to defer a portion of these planned capital expenditures depending on a variety of factors, including but not limited to the success of our drilling activities, prevailing and anticipated prices for oil, natural gas and NGL, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners. Any postponement or elimination of our development drilling program could result in a reduction of proved reserve volumes and related standardized measure. These risks could materially affect our business, financial condition and results of operations.

Adjusted EBITDAX

Adjusted EBITDAX is not a measure of net income (loss) as determined by United States GAAP. Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDAX as net income (loss) adjusted for certain cash and non-cash items, including depletion, depreciation, amortization and

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accretion (DD&A), impairment of long lived assets, non-recurring charges in other operating expenses, exploration and abandonment expenses, gain on sale of property and equipment, (gain) loss on commodity derivatives, settlements on commodity derivative instruments, premiums paid for derivatives that settled during the period, stock-based compensation expense, amortization of debt issuance costs, gain on repurchase of senior notes, interest expense, income tax expense (benefit) and loss on deconsolidation of Elevation Midstream, LLC. Adjusted EBITDAX is also used to evaluate the performance of reportable segments. Please see Note 15—Segment Information in Part I, Item 1. Financial Information of this Quarterly Report for more information regarding the EBITDAX of reportable segments.

Management believes Adjusted EBITDAX is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income (loss) as determined in accordance with GAAP or as an indicator of our operating performance. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital, hedging strategy and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX. Our computations of Adjusted EBITDAX may not be comparable to other similarly titled measure of other companies. We believe that Adjusted EBITDAX is a widely followed measure of operating performance. Additionally, our management team believes Adjusted EBITDAX is useful to an investor in evaluating our financial performance because this measure (i) is widely used by investors in the oil and natural gas industry to measure a company’s operating performance without regard to items excluded from the calculation of such term, among other factors; (ii) helps investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital structure from our operating structure; and (iii) is used by our management team for various purposes, including as a measure of operating performance, in presentations to our board of directors, as a basis for strategic planning and forecasting.

The following table presents a reconciliation of Adjusted EBITDAX to the GAAP financial measure of net income (loss) for each of the periods indicated (in thousands).

	For the Three Months Ended March 31,
	2020		2019
Reconciliation of Net Income (Loss) to Adjusted EBITDAX:
Net income (loss)	$	9,037	$	(94,032)
Add back:
Depletion, depreciation, amortization and accretion	76,051		118,770
Impairment of long lived assets	775		8,248
Other operating expenses	52,575		—
Exploration and abandonment expenses	112,480		6,194
Gain on sale of property and equipment	—		(222)
(Gain) loss on commodity derivatives	(263,015)		122,091
Settlements on commodity derivative instruments	39,295		(10,329)
Premiums paid for derivatives that settled during the period	—		(9,549)
Stock-based compensation expense	—		13,008
Amortization of debt issuance costs	1,242		1,497
Gain on repurchase of 2026 Senior Notes	—		(7,317)
Interest expense	20,116		18,828
Income tax expense (benefit)	2,200		(29,000)
Loss on deconsolidation of Elevation Midstream, LLC	73,139		—
Adjusted EBITDAX	$	123,895	$	138,187

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Free Cash Flow

Our Free Cash Flow is not a measure of net income (loss) as determined by GAAP. We define Free Cash Flow as Discretionary Cash Flow (non-GAAP) less Adjusted Cash Flow used in Investing (non-GAAP) adjusted for Other Non-Recurring Adjustments (non-GAAP). Discretionary Cash Flow is defined as net cash provided by operating activities (GAAP) less changes in working capital (current assets and liabilities). Adjusted Cash Flow used in Investing is defined as cash flow used in investing activities (GAAP) adjusted for changes in accounts payable and accrued liabilities related to capital expenditures.

Free Cash Flow is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We believe Free Cash Flow can provide additional transparency into the drivers of trends in our operating cash flows, such as production, realized sales prices and operating costs, as it disregards the timing of settlement of operating assets and liabilities. We believe Free Cash Flow provides additional information that may be useful in an analysis of our ability to generate cash to fund exploration and development activities, construct and support midstream assets, and to return capital to stockholders.

The following tables present a reconciliation of Discretionary Cash Flow and Free Cash Flow to the GAAP financial measure of net cash provided by operating activities for each of the periods indicated.

	Upstream		Midstream		Consolidated
	For the Three Months Ended March 31, 2020
Cash Flow from Operating Activities
Net cash provided by operating activities	$	144,219	$	2,880	$	147,099
Changes in current assets and liabilities	(101,047)		(1,907)		(102,954)
Discretionary Cash Flow	43,172		973		44,145
Cash Flow from Investing Activities
Net cash used in investing activities	(133,863)		(5,840)		(139,703)
Change in accounts payable and accrued liabilities related to capital expenditures	(10,477)		2,210		(8,267)
Adjusted Cash Flow used in Investing	(144,340)		(3,630)		(147,970)
Other Non-Recurring Adjustments(1)	1,170		—		1,170
Free Cash Flow	$	(99,998)	$	(2,657)	$	(102,655)

	Upstream		Midstream		Consolidated
	For the Three Months Ended March 31, 2019
Cash Flow from Operating Activities
Net cash provided by operating activities	$	131,121	$	2,990	$	134,111
Changes in current assets and liabilities	3,634		(447)		3,187
Discretionary Cash Flow	134,755		2,543		137,298
Cash Flow from Investing Activities
Net cash used in investing activities	(184,719)		(47,656)		(232,375)
Change in accounts payable and accrued liabilities related to capital expenditures	8,350		(9,566)		(1,216)
Adjusted Cash Flow used in Investing	(176,369)		(57,222)		(233,591)
Other Non-Recurring Adjustments(1)	1,582		—		1,582
Free Cash Flow	$	(40,032)	$	(54,679)	$	(94,711)

(1) Amount incurred for the construction of our field office that is included in other property and equipment in our condensed consolidated statements of cash flows.

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Items Affecting the Comparability of Our Financial Results

Our historical results of operations for the periods presented may not be comparable, either to each other or to our future results of operations, for the reasons described below:

•For the three months ended March 31, 2020 and 2019, respectively, exploration and abandonment expenses increased primarily due to the abandonment of $106.9 million and $3.9 million of unproved properties.

•Elevation Midstream, LLC was deconsolidated as of March 16, 2020 and accounted for as an equity method investment. We elected the fair value option to remeasure the Elevation Midstream, LLC equity method investment and determined it had no fair value. We recorded a $73.1 million loss on deconsolidation of Elevation Midstream, LLC in the condensed consolidated statements of operations for the three months ended March 31, 2020. Please see Note 1—Business and Organization in Part I, Item 1. Financial Information of this Quarterly Report for information related to the deconsolidation of Elevation Midstream, LLC.

•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. While the Company disputes that these amounts are due to Elevation, under ASC Topic 450 - Contingencies, we recorded the amount in other operating expenses on the condensed consolidated statements of operations for the three months ended March 31, 2020.

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Historical Results of Operations and Operating Expenses

Oil, Natural Gas and NGL Sales Revenues, Operating Expenses and Other Income (Expense).

For components of our revenues, operating expenses, other income (expense) and net income (loss), please see our condensed consolidated statements of operations in Part I, Item 1. Financial Information of this Quarterly Report.

The following table provides a summary of our sales volumes, average prices and operating expenses on a per BOE basis for the periods indicated:

	For the Three Months Ended
	March 31,
	2020			2019
Sales (MBoe)(1):	8,576			7,236
Oil sales (MBbl)	3,504			3,583
Natural gas sales (MMcf)	19,003			13,959
NGL sales (MBbl)	1,906			1,327
Sales (BOE/d)(1):	94,247			80,401
Oil sales (Bbl/d)	38,502			39,809
Natural gas sales (Mcf/d)	208,819			155,103
NGL sales (Bbl/d)	20,942			14,742
Average sales prices(2):
Oil sales (per Bbl)(3)	$	35.45		$	46.17
Oil sales with derivative settlements (per Bbl)(3)	45.50			41.89
Natural gas sales (per Mcf)	1.17			2.57
Natural gas sales with derivative settlements (per Mcf)	1.39			2.25
NGL sales (per Bbl)	9.02			15.53
Average price (per BOE)(3)	19.09			30.67
Average price with derivative settlements (per BOE)(3)	23.67			27.92
Expense per BOE:
Lease operating expenses	$	3.54		$	3.02
Transportation and gathering	2.66			1.43
Production taxes	1.57			2.51
Exploration and abandonment expenses	13.11			0.86
Depletion, depreciation, amortization and accretion	8.87			16.41
General and administrative expenses	1.24			3.82
Cash general and administrative expenses(4)	1.24			2.02
Stock-based compensation	—			1.80
Total operating expenses per BOE(5)	$	30.99		$	28.05
Production taxes as a percentage of revenue	8.1		%	8.2		%

(1)One BOE is equal to six Mcf of natural gas or one Bbl of oil or NGL based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities.

(2)Average prices shown in the table reflect prices both before and after the effects of our settlements of commodity derivative contracts. Our calculation of such effects includes both gains and losses on settlements for commodity derivatives and amortization of premiums paid or received on options that settled during the period.

(3)Includes amounts allocated to a satisfied performance obligation, recognized within oil sales for the three months ended March 31, 2020, pursuant to ASC 606, Revenue Recognition.

(4)Cash general and administrative expenses for the three months ended March 31, 2020 includes expense of $2.2 million related to the terms of a separation agreement with a former executive officer. Excluding this one-time expense results in cash general and administrative expense per BOE of $0.97 for the three months ended March 31, 2020.

(5)Excludes midstream operating expenses, impairment of long lived assets, gain on sale of property and equipment, and other operating expenses.

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Three Months Ended March 31, 2020 Compared to Three Months Ended March 31, 2019

Oil sales revenues. Crude oil sales revenues decreased by $41.2 million to $124.2 million for the three months ended March 31, 2020 as compared to crude oil sales of $165.4 million for the three months ended March 31, 2019. A decrease in sales volumes between these periods contributed a $3.7 million negative impact, and a decrease in crude oil prices contributed a $37.5 million negative impact. For the three months ended March 31, 2020, crude oil revenue decreased by approximately $8.5 million due to the impact of the increase in the forecasted deferral balance on one of our revenue contracts. Pursuant to ASC 606, the contract term impacts the amount of consideration that can be included in the transaction price, which reduced oil sales revenue.

For the three months ended March 31, 2020, our crude oil sales averaged 38.5 MBbl/d. Our crude oil sales volume decreased by 0.1 to 3.5 MBbl for the three months ended March 31, 2020 compared to 3.6 MBbl for the three months ended March 31, 2019. The volume decrease is primarily due to the natural decline of our existing properties, partially offset by an increase in production from the completion of 28 gross wells from January 1, 2020 to March 31, 2020.

The average price we realized on the sale of crude oil was $35.45 per Bbl for the three months ended March 31, 2020 compared to $46.17 per Bbl for the three months ended March 31, 2019, primarily due to changes in market prices for crude oil and the $8.5 million decrease of crude oil revenue explained above.

Natural gas sales revenues. Natural gas sales revenues decreased by $13.6 million to $22.3 million for the three months ended March 31, 2020 as compared to natural gas sales revenues of $35.9 million for the three months ended March 31, 2019. An increase in sales volumes between these periods contributed a $13.0 million positive impact, while a decrease in natural gas prices contributed a $26.6 million negative impact.

For the three months ended March 31, 2020, our natural gas sales averaged 208.8 MMcf/d. Natural gas sales volumes increased by 5.0 to 19.0 MMcf for the three months ended March 31, 2020 as compared to 14.0 MMcf for the three months ended March 31, 2019. The volume increase is primarily due to the completion of 28 gross wells from January 1, 2020 to March 31, 2020, partially offset by the natural decline on existing producing properties.

The average price we realized on the sale of our natural gas was $1.17 per Mcf for the three months ended March 31, 2020 compared to $2.57 per Mcf for the three months ended March 31, 2019, primarily due to capacity constraints in transporting the wet gas associated with crude oil production coupled with negative market conditions surrounding limited export capacity.

NGL sales revenues. NGL sales revenues decreased by $3.4 million to $17.2 million for the three months ended March 31, 2020 as compared to NGL sales revenues of $20.6 million for the three months ended March 31, 2019. An increase in sales volumes between these periods contributed a $8.9 million positive impact, while a decrease in price contributed a $12.3 million negative impact.

For the three months ended March 31, 2020, our NGL sales averaged 20.9 MBbl/d. NGL sales volumes increased by 0.6 to 1.9 MBbl for the three months ended March 31, 2020 as compared to 1.3 MBbl for the three months ended March 31, 2019. The volume increase is primarily due to the completion of 28 gross wells during the three months ended March 31, 2020, partially offset by the natural decline on existing producing properties. Our NGL sales are directly associated with our natural gas sales because our natural gas volumes are processed by third parties for both residue natural gas sales and NGL sales.

The average price we realized on the sale of our NGL was $9.02 per Bbl for the three months ended March 31, 2020 compared to $15.53 per Bbl for the three months ended March 31, 2019, primarily due to capacity constraints in transporting the wet gas associated with crude oil production coupled with negative market conditions surrounding limited export capacity.

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Lease operating expenses. Our LOE increased by $8.5 million to $30.4 million for the three months ended March 31, 2020, from $21.9 million for the three months ended March 31, 2019. The increase in LOE was primarily the result of an increase in producing wells and an increase in workover repairs, partially offset by optimization of our field cost structure during the three months ended March 31, 2020. On a per unit basis, LOE increased to $3.54 per BOE sold for the three months ended March 31, 2020 from $3.02 per BOE for the three months ended March 31, 2019.

Transportation and gathering ("T&G"). Our T&G expense increased by $12.4 million to $22.8 million for the three months ended March 31, 2020, from $10.4 million for the three months ended March 31, 2019. The increase in T&G was primarily due to an increase of volumes on a certain gathering system during the three months ended March 31, 2020 compared to the three months ended March 31, 2019. On a per unit basis, T&G increased to $2.66 per BOE sold for the three months ended March 31, 2020 compared to $1.43 per BOE sold for the three months ended March 31, 2019.

Production taxes. Our production taxes decreased by $4.6 million to $13.5 million for the three months ended March 31, 2020 as compared to $18.1 million for the three months ended March 31, 2019. The decrease is primarily attributable to decreased revenue as production taxes are calculated as a percentage of sales revenue. Production taxes as a percentage of sales revenue was 8.1% for the three months ended March 31, 2020 as compared to 8.2% for the three months ended March 31, 2019. The consistency in production taxes as a percentage of sales revenue relates to comparatively constant estimated ad valorem and severance tax rates for the three months ended March 31, 2020.

Exploration and abandonment expenses. Our exploration and abandonment expenses were $112.5 million for the three months ended March 31, 2020, of which $106.9 million was lease abandonment expense. Due to the decrease in pricing, all of the unproved property in our northern field was abandoned and impaired. For the three months ended March 31, 2019, we recognized $6.2 million in exploration and abandonment expenses.

Depletion, depreciation, amortization and accretion expense. Our DD&A expense decreased $42.7 million to $76.1 million for the three months ended March 31, 2020 as compared to $118.8 million for the three months ended March 31, 2019. On a per unit basis, DD&A expense decreased to $8.87 per BOE for the three months ended March 31, 2020 from $16.41 per BOE for the three months ended March 31, 2019. This decrease is due to an impairment of $1.3 billion of proved oil and gas properties that occurred during the fourth quarter of 2019.

Impairment of long lived assets. For the three months ended March 31, 2020 and 2019, impairment expense was $0.8 million and $8.2 million, respectively, related to impairment of the proved oil and gas properties in our northern field as the fair value did not exceed the carrying amount associated with the properties.

General and administrative expenses ("G&A"). General and administrative expenses decreased by $17.1 million to $10.6 million for the three months ended March 31, 2020 as compared to $27.7 million for the three months ended March 31, 2019. This decrease is primarily due to a one-time reduction of workforce during the first quarter of 2020, and a decrease in stock-based compensation expense recognized for the three months ended March 31, 2020 compared to the three months ended March 31, 2019. On a per unit basis, G&A expense decreased to $1.24 per BOE sold for the three months ended March 31, 2020 from $3.82 per BOE sold for the three months ended March 31, 2019.

Our G&A expenses for the three months ended March 31, 2020 includes $2.2 million related to the terms of a separation agreement with a former executive officer. No expenses of this nature were incurred during the three months ended March 31, 2019.

Our G&A expenses include the non-cash expense for stock-based compensation for equity awards granted to our employees and directors. For the three months ended March 31, 2020, there was no stock-based compensation expense primarily as a result of a true-up related to forfeitures in connection with the workforce reduction in February 2020. For the three months ended March 31, 2019, stock-based compensation expense was $13.0 million.

Other operating expenses. Other operating expenses were $52.6 million for the three months ended March 31, 2020. This amount is primarily made up of a $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

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facility prior to April 1, 2020. Also included in this amount is a $5.8 million charge to income for expenses related to a workforce reduction in February 2020.

Commodity derivative gain (loss). Primarily due to the decrease in NYMEX crude oil futures prices at March 31, 2020 as compared to December 31, 2019 and change in fair value from the execution of new positions, we incurred a net gain on our commodity derivatives of $263.0 million for the three months ended March 31, 2020. Primarily due to the increase in NYMEX crude oil futures prices at March 31, 2019 as compared to December 31, 2018 and change in fair value from the execution of new positions, we incurred a net loss on our commodity derivatives of $122.1 million for the three months ended March 31, 2019, including the amortization of premiums. These gains and losses are a result of our hedging program, which is used to mitigate our exposure to commodity price fluctuations. The fair value of the open commodity derivative instruments will continue to change in value until the transactions are settled and we will likely add to our hedging program in the future. Therefore, we expect our net income (loss) to reflect the volatility of commodity price forward markets. Our cash flow will only be affected upon settlement of the transactions at the current market prices at that time. During the three months ended March 31, 2020, we received cash settlements of commodity derivatives totaling $39.3 million. During the three months ended March 31, 2019, we paid settlements of commodity derivatives totaling $10.3 million.

Loss on deconsolidation of Elevation Midstream, LLC. On March 16, 2020, we deconsolidated Elevation Midstream, LLC. Upon deconsolidation, we 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 Elevation Midstream, LLC in the condensed consolidated statements of operations for the three months ended March 31, 2020.

Interest expense. Interest expense consists of interest expense on our long-term debt and amortization of debt issuance costs, net of capitalized interest. For the three months ended March 31, 2020, we recognized interest expense of $21.4 million as compared to $13.0 million for the three months ended March 31, 2019, as a result of borrowings under our revolving credit facility, our 2024 Senior Notes, our 2026 Senior Notes and the amortization of debt issuance costs.

We incurred interest expense for the three months ended March 31, 2020 of $22.3 million related to our 2024 Senior Notes, 2026 Senior Notes, and revolving credit facility. We incurred interest expense for the three months ended March 31, 2019 of approximately $20.8 million related to our revolving credit facility, our 2024 Senior Notes, and our 2026 Senior Notes. Also included in interest expense for the three months ended March 31, 2020 and 2019 was the amortization of debt issuance costs of $1.2 million and $1.5 million, respectively. For the three months ended March 31, 2020 and 2019, we capitalized interest expense of $2.1 million and $2.0 million, respectively. Interest expense for the three months ended March 31, 2019 also includes $7.3 million of gain on debt extinguishment upon the repurchase of our 2026 Senior Notes.

Income tax (expense) benefit. We recorded an income tax expense and benefit of $2.2 million and $29.0 million, respectively, for the three months ended March 31, 2020 and 2019, respectively. This resulted in an effective tax rate of approximately 19.6% and 23.6% for the three months ended March 31, 2020 and 2019, respectively. Our effective tax rate for the three months ended March 31, 2020 and 2019 differs from the U.S. statutory income tax rates of 21.0% primarily due to the effects of state income taxes, estimated taxable permanent differences, and valuation allowance.

Gathering and facilities segment. Prior to March 31, 2020, we 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, operation and support of midstream assets to gather and process crude oil and gas production (the "gathering and facilities segment"). Please see Note 1—Business and Organization in Part I, Item I, Financial Information of this Quarterly Report for further information related to the deconsolidation of Elevation Midstream, LLC. After March 31, 2020, Extraction will report as a single operating segment.

In October 2019, Elevation commenced moving crude oil, natural gas and water through its Badger central gathering facility. Because Elevation had no revenue and insignificant operating expenses for the three months ended March 31, 2019, comparison to the three months ended March 31, 2020 is not relevant. For the three months ending March 31, 2020, our gathering and facilities segment had revenues of $5.9 million and direct operating expenses of $3.9

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million. General and administrative expenses were $1.1 million for both of the three months ended March 31, 2020 and 2019. For the three months ended March 31, 2020, depreciation expense was $1.1 million as the gathering facility was placed into service during the fourth quarter of 2019. Please see Note 15—Segments in Part I, Item I, Financial Information of this Quarterly Report.

Liquidity and Capital Resources

Current Financial Condition and Liquidity

The market price for oil, natural gas and NGLs decreased significantly beginning in the first quarter of 2020, continuing into the second quarter of 2020. The decrease in the market price for our production directly reduces our cash flow from operations and indirectly impacts other potential sources of funds described above. Our ability to continue as a going concern is dependent upon attaining and maintaining profitable operations and, until that time, raising additional capital as needed, but there can be no assurance that we will be able to raise sufficient financing on terms that are acceptable to us, or at all. As discussed in Note 4—Going Concern in Part I, Item I, Financial Information of this Quarterly Report, on April 27, 2020 the lenders under the revolving credit facility elected to reduce the borrowing base and elected commitments to $650.0 million from $950.0 million, and we borrowed all of the remaining available capacity under the revolving credit facility. As a result of the reduction of the borrowing base and elected commitments, it is probable that we will not meet the financial covenants under the revolving credit facility for the three months ended June 30, 2020 when assuming our current financial forecast.

We may seek covenant relief from the lenders under the revolving credit facility, and if we do not obtain a waiver of financial covenants for the three months ended June 30, 2020, the lenders under the revolving credit facility will be able to declare all outstanding principal and interest to be due and payable, and the lenders under the credit agreement could terminate their commitments to loan money and could foreclose against the assets collateralizing their borrowings. Any acceleration of the obligations under the revolving credit facility would result in a cross-default and potential acceleration of the maturity of our other outstanding long-term debt. These potential defaults create uncertainty associated with our ability to repay outstanding long-term debt obligations as they become due and creates a substantial doubt over our ability to continue as a going concern.

As a result of the impacts to our financial position resulting from declining commodity price conditions and in consideration of the substantial amount of long-term debt and preferred stock outstanding, we have engaged advisors to assist with the evaluation of strategic alternatives, which may include, but not be limited to, seeking a restructuring, amendment or refinancing of existing debt through a private restructuring or reorganization under Chapter 11 of the Bankruptcy Code. However, there can be no assurances that we will be able to successfully restructure our indebtedness, improve our financial position or complete any strategic transactions. As a result of these uncertainties and the likelihood of a restructuring or reorganization, management has concluded that there is substantial doubt regarding our ability to continue as a going concern.

Sources of Liquidity and Capital Resources

Historically, our primary sources of liquidity have been borrowings under our revolving credit facility, proceeds from notes offerings and preferred stock offerings, equity provided by investors, including our management team, cash from issuance of preferred stock, and cash flows from divestitures and from the sale of oil, gas and NGL production. Our primary uses of capital have been for the acquisition of oil and gas properties to increase our acreage position, as well as development and exploration of oil and gas properties. Our borrowings, net of unamortized debt issuance costs, were approximately $1,556.3 million and $1,555.8 million at March 31, 2020, and December 31, 2019, respectively. We also have other contractual commitments, which are described in Note 13—Commitments and Contingencies in Part I, Item 1, Financial Information of this Quarterly Report.

We may from time to time seek to retire or purchase our outstanding notes through cash purchases and/or exchanges (including for equity securities), in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

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We plan to continue our practice of entering into hedging arrangements to reduce the impact of commodity price volatility on our cash flow from operations. Under this strategy, we intend to enter into commodity derivative contracts at times and on terms desired to maintain a portfolio of commodity derivative contracts covering approximately 50% to 70% of our projected oil and natural gas production over a one to two year period at a given point in time, although we may from time to time hedge more or less than this approximate range.

If cash flow from operations does not meet our expectations, we may further reduce our expected level of capital expenditures and/or fund a portion of our capital expenditures using borrowings under our revolving credit facility, issuances of debt and equity securities or from other sources, such as asset sales. We cannot assure you that necessary capital will be available on acceptable terms or at all. Our ability to raise funds through the incurrence of additional indebtedness could be limited by the covenants in our debt arrangements. If we are unable to obtain funds when needed or on acceptable terms, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to maintain our production or proved reserves.

We had a Stock Repurchase Program that ended in 2019. During the three months ended March 31, 2019. Spending under this program was $60.0 million. We also have a Senior Notes Repurchase Program in place. Spending under this program during the three months ended March 31, 2019 was $28.5 million. No Senior Notes were repurchased during the three months ended March 31, 2020. We are authorized to repurchase up to $100.0 million of our Senior Notes.

Cash Flows

The following table summarizes our cash flows for the periods indicated (in thousands):

	For the Three Months Ended
	March 31,
	2020		2019
Net cash provided by operating activities	$	147,099	$	134,111
Net cash used in investing activities	$	(139,703)	$	(232,375)
Net cash used in financing activities	$	(57)	$	(23,951)

Three Months Ended March 31, 2020 Compared to Three Months Ended March 31, 2019

Net cash provided by operating activities. For the three months ended March 31, 2020 as compared to the three months ended March 31, 2019, our net cash provided by operating activities increased by $13.0 million, primarily due to an increase of $59.4 million related to changes in working capital and an increase of $28.5 million in commodity derivative settlement payments offset by a decrease in operating revenues net of expenses of $76.9 million primarily as a result of a decrease in commodity prices.

Net cash used in investing activities. For the three months ended March 31, 2020, net cash used in investing activities decreased by $92.7 million compared to the three months ended March 31, 2019 primarily as a result of $45.0 million less spent on oil and gas property additions, $53.4 million less spent on gathering systems and facilities and $5.2 million less spent on other property and equipment offset by $5.1 million more spent on our investment in unconsolidated subsidiaries. Also, the proceeds from the sale of assets were $4.4 million less during the first quarter of 2020 than during the same period in 2019.

Net cash used in financing activities. For the three months ended March 31, 2020, net cash used in financing activities was $23.9 million less than for the three months ended March 31, 2019 primarily as a result of $28.5 million spent to repurchase 2026 Senior Notes and $32.2 million spent to repurchase of common stock during the first quarter of 2019 which were not spent during first quarter of 2020. Also, net borrowings on the credit facility during the first quarter of 2019 were $40.0 million compared to none during the first quarter of 2020.

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Working Capital

Our working capital deficit was $144.6 million and $240.8 million at March 31, 2020 and December 31, 2019, respectively. Our cash balances totaled $32.0 million and $32.4 million at March 31, 2020 and December 31, 2019, respectively.

Due to the amounts that we incur related to our drilling and completion program and the timing of such expenditures, we may incur working capital deficits in the future. We expect that our pace of development, production volumes, commodity prices and differentials to NYMEX prices for our oil, natural gas and NGL production will be the largest variables affecting our working capital. Due to the oil, natural gas and NGL price declines during the first and second quarter of 2020, we modified our drilling rig contracts to have minimal drilling activity for the remainder of the year. Please see Note 13—Commitments and Contingencies and Note 4—Going Concern in Part 1, Item 1. Financial Information of this Quarterly Report.

Debt Arrangements

For details of our debt arrangements including our credit facility, 2024 Senior Notes and 2026 Senior Notes, please see Note 5—Long-Term Debt in Part I, Item 1. Financial Information of this Quarterly Report. Additional debt disclosures specific to this Management Discussion and Analysis section are as follows.

If we experience certain kinds of changes of control, holders of our 2024 and 2026 Senior Notes may have the right to require us to repurchase their notes at 101% of the principal amount of the notes, plus accrued and unpaid interest, if any, to the date of purchase.

Equity Arrangements

For details of our equity arrangements including our Series A Preferred Stock and Elevation Preferred Units, please see Note 11—Equity in Part I, Item 1. Financial Information of this Quarterly Report.

Critical Accounting Policies and Estimates

There were no material changes to our critical accounting policies and estimates from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2019 other than the deconsolidation of Elevation Midstream, LLC discussed in Note 1—Business and Organization in Part I, Item 1. Financial Information of this Quarterly Report.

Recent Accounting Pronouncements

Please see Note 2—Basis of Presentation, Significant Accounting Policies and Recent Accounting Pronouncements in Part 1, Item 1 of this Quarterly Report for a detailed list of recent accounting pronouncements.

Impact of Inflation/Deflation and Pricing

All of our transactions are denominated in U.S. dollars. Typically, as prices for oil and natural gas increase, associated costs rise. Conversely, as prices for oil and natural gas decrease, costs decline. Cost declines tend to lag and may not adjust downward in proportion to declining commodity prices. Historically, field-level prices received for our oil and natural gas production have been volatile. During the year ended December 31, 2019, commodity prices increased during the first, second and third quarter, and subsequently decreased in the fourth quarter. During the three months ended March 31, 2020, commodity prices decreased compared to the same period in 2019. Changes in commodity prices impact our revenues, estimates of reserves, assessments of any impairment of oil and natural gas properties, as well as values of properties being acquired or sold. Price changes have the potential to affect our ability to raise capital, borrow money, and retain personnel.

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Off-Balance Sheet Arrangements

As of March 31, 2020, we did not have material off-balance sheet arrangements.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil, natural gas and NGL prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. All of our market risk sensitive instruments were entered into for purposes other than speculative trading. LIBOR is used as a reference rate for certain of our financial instruments, such as our revolving credit facility. LIBOR is set to be phased out at the end of 2021. We are currently reviewing how the LIBOR phase-out will affect the Company, but we do not expect the impact to be material.

Commodity Price Risk

Our major market risk exposure is in the pricing that we receive for our oil, natural gas and NGL production. Pricing for oil, natural gas and NGL has been volatile and unpredictable for several years and this volatility is expected to continue in the future. The prices we receive for our oil, natural gas and NGL production depend on many factors outside of our control, such as the strength of the global economy and global supply and demand for the commodities we produce.

To reduce the impact of fluctuations in oil and natural gas prices on our revenues, we have periodically entered into commodity derivative contracts with respect to certain of our oil and natural gas production through various transactions that limit the downside of future prices received. We plan to continue our practice of entering into such transactions to reduce the impact of commodity price volatility on our cash flow from operations. Future transactions may include price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty. Additionally, we may enter into collars, whereby we receive 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 prices at targeted levels and to manage our exposure to oil price fluctuations.

For a summary of the Company’s commodity derivative contracts as of March 31, 2020, please see Note 6—Commodity Derivative Instruments in Part 1, Item 1 of this Quarterly Report.

As of March 31, 2020, the fair market value of our oil derivative contracts was a net asset of $236.4 million. Based on our open oil derivative positions at March 31, 2020, a 10% increase in the NYMEX WTI price would decrease our net oil derivative asset by approximately $34.2 million, while a 10% decrease in the NYMEX WTI price would increase our net oil derivative asset by approximately $30.6 million. As of March 31, 2020, the fair market value of our natural gas derivative contracts was a net asset of $16.0 million. Based upon our open commodity derivative positions at March 31, 2020, a 10% increase in the NYMEX Henry Hub price would decrease our net natural gas derivative asset by approximately $3.8 million, while a 10% decrease in the NYMEX Henry Hub price would increase our net natural gas derivative asset by approximately $3.9 million. Please see “—How We Evaluate Our Operations—Derivative Arrangements.”

Counterparty and Customer Credit Risk

Our cash and cash equivalents are exposed to concentrations of credit risk. We manage and control this risk by investing these funds with major financial institutions. We often have balances in excess of the federally insured limits.

We sell oil, natural gas and NGL to various types of customers, including 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 of our control, none of

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which can be predicted with certainty. For the three months ended March 31, 2020, we had certain major customers that exceeded 10% of total oil, natural gas and NGL revenues. We do not believe the loss of any single purchaser would materially impact our operating results because oil, natural gas and NGL are fungible products with well-established markets and numerous purchasers.

At March 31, 2020, we had commodity derivative contracts with 9 counterparties. We do not require collateral or other security from counterparties to support derivative instruments; however, to minimize the credit risk in derivative instruments, it is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. Additionally, we use master netting agreements to minimize credit risk exposure. The creditworthiness of our counterparties is subject to periodic review. For the three months ended March 31, 2020 and 2019, we did not incur any losses with respect to counterparty contracts. None of our existing derivative instrument contracts contain credit risk related contingent features.

Interest Rate Risk

At March 31, 2020, we had $470.0 million variable-rate debt outstanding. The impact on interest expense of a 1% increase or decrease in the average interest rate would be approximately $4.7 million per year. We may begin entering into interest rate swap arrangements on a portion of our outstanding debt to mitigate the risk of fluctuations in LIBOR if we have variable-rate debt outstanding in the future. Please see “—Liquidity and Capital Resources—Debt Arrangements.”

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our principal executive officer and principal financial officer, evaluated the effectiveness of our disclosure controls and procedures to ensure that the information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and to ensure that such information is accumulated and communicated to management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure. Based upon that evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were not effective as of March 31, 2020, due to the material weakness in internal control over financial reporting as described below.

Management's Material Weakness Remediation Plan

A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. Management determined that the Company did not design and maintain effective controls to determine the appropriate contract termination date and evaluate the potential accounting implications of changes in termination dates of contracts with customers. This material weakness resulted in a restatement of the Company’s condensed consolidated financial statements as of and for the three and nine month periods ended September 30, 2019 and immaterial errors to the consolidated financial statements for the periods ended December 31, 2018, March 31, 2019 and June 30, 2019. The line items affected were oil sales, accounts payable and accrued liabilities, other non-current liabilities, inventory, prepaid expenses and other, and other non-current assets. Additionally, this material weakness could result in a misstatement of the aforementioned financial statement line items or disclosures that would result in a material misstatement to the annual or interim consolidated financial statements that would not be prevented or detected.

The Company and its Board of Directors are committed to maintaining a strong internal control environment. Management has evaluated the material weakness described above and developed a remediation plan to address the material weakness. The remediation plan includes additional procedures around determining the contract termination date pursuant to the accounting treatment under ASC 606 - Revenue from Contracts with Customers. Management is committed to successfully implementing the remediation plan and plans to commence the evaluation of its updated design of internal controls for implementation expeditiously.

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Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the three months ended March 31, 2020 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II—OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Information regarding our legal proceedings can found in Note 13—Commitments and Contingencies — Litigation and Legal Items in Part I, Item 1. Financial Information in this Quarterly Report.

ITEM 1A. RISK FACTORS

Factors that could materially adversely affect our business, financial condition, operating results or liquidity and the trading price of our common stock are described below and under Item 1A "Risk Factors", included in our Annual Report on Form 10-K filed with the SEC on March 12, 2020. The risks described below and in our annual report are not the only risks facing us. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results. This information should be considered carefully, together with other information in this report and other reports and materials we file with the SEC.

We have no additional borrowing capacity under our revolving credit facility. Unless we are able to successfully restructure our existing indebtedness, obtain further waivers or forbearance from our existing lenders or otherwise raise significant capital, it is unlikely that we will be able to meet our obligations as they become due, and we may not be able to continue as a going concern.

Our working capital deficit was $144.6 million and $240.8 million at March 31, 2020 and December 31, 2019, respectively, and our cash balances totaled $32.0 million and $32.4 million at March 31, 2020 and December 31, 2019, respectively. For the year ended December 31, 2019, the Company incurred net losses of approximately $1.4 billion. Our continuation as a going concern is dependent upon attaining and maintaining profitable operations and, until that time, raising additional capital as needed, but there can be no assurance that we will be able to obtain sufficient financing. Our ability to generate positive cash flow from operations is dependent upon generating sufficient revenues. To date, our operations have been funded by the sale of oil, gas and NGL production based on prevailing market prices, which decreased significantly in March and April 2020. Our operations have also been funded through availability on our credit facility. As discussed in Note 4—Going Concern in Part I, Item I, Financial Information of this Quarterly Report, on April 27, 2020 the lenders under the revolving credit facility elected to reduce the borrowing base and elected commitments to $650.0 million from $950.0 million, and we borrowed all of the remaining available capacity under the revolving credit facility. As a result of the reduction of the borrowing base and elected commitments, it is probable that the Company will not meet the financial covenants under the revolving credit facility for the three months ended June 30, 2020 when assuming the Company’s current financial forecast.

If the Company does not obtain a waiver of its financial covenants for the three months ended June 30, 2020, the lenders under the revolving credit facility will be able to accelerate maturity of the debt. Any acceleration of the obligations under the revolving credit facility would result in a cross-default and potential acceleration of the maturity of the Company’s other outstanding long-term debt. These defaults create uncertainty associated with the Company’s ability to repay its outstanding long-term debt obligations as they become due and creates a substantial doubt over the Company’s ability to continue as a going concern.

The accompanying Consolidated Financial Statements have been prepared on a going concern basis which contemplates continuity of operations, realization of assets and liquidation of liabilities in the ordinary course of business. The accompanying condensed consolidated financial statements do not reflect any adjustments that might result if we are unable to continue as a going concern. Our substantial indebtedness, liquidity issues and efforts to negotiate restructuring transactions may result in uncertainty about our business and cause, among other things:

•third parties to lose confidence in our ability to explore and produce oil and natural gas, resulting in a significant decline in our revenues, profitability and cash flow;

•difficulty retaining, attracting or replacing key employees;

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•employees to be distracted from performance of their duties or more easily attracted to other career opportunities; and

•our suppliers, vendors, hedge counterparties and service providers to renegotiate the terms of our agreements, terminate their relationship with us or require financial assurances from us.

These events may have a material adverse effect on our business and operations.

The excess supply of oil and natural gas resulting from the reduced demand caused by the COVID-19 pandemic and the effects of actions by, or disputes among or between, oil and natural gas producing countries may result in transportation and storage constraints, reduced production and shut-in of our wells, any of which would adversely affect our business, financial condition and results of operations.

The recent worldwide outbreak of COVID-19, the uncertainty regarding the impact of COVID-19 and various governmental actions taken to mitigate the impact of COVID-19, have resulted in an unprecedented decline in demand for oil and natural gas. At the same time, the decision by Saudi Arabia in March 2020 to drastically reduce export prices and increase oil production followed by curtailment agreements among OPEC and other countries such as Russia further increased uncertainty and volatility around global oil supply-demand dynamics. To the extent that the outbreak of COVID-19 continues to negatively impact demand and OPEC members and other oil exporting nations fail to implement production cuts or other actions that are sufficient to support and stabilize commodity prices, we expect there to be excess supply of oil and natural gas for a sustained period. This excess supply could, in turn, result in transportation and storage capacity constraints in the United States, including in the DJ Basin. If, in the future, our transportation or storage arrangements become constrained, we may incur significant operational costs if there is an increase in price for services or we may be required to shut-in or curtail production or flare our natural gas. If we were required to shut-in wells, we might also be obligated to pay certain demand charges for gathering and processing services and firm transportation charges for pipeline capacity we have reserved. Further, any prolonged shut-in of our wells may result in decreased well productivity once we are able to resume operations, and any cessation of drilling and development of our acreage could result in the expiration, in whole or in part, of our leases. All of these impacts resulting from the confluence of the COVID-19 pandemic and the price war between Saudi Arabia and Russia may adversely affect our business, financial condition and results of operations.

Due to the commodity price environment, we have postponed or eliminated a portion of our developmental drilling. A sustained period of weakness in oil, natural gas and NGLs prices, and the resultant effects of such prices on our drilling economics and ability to raise capital, will require us to reevaluate and further postpone or eliminate additional drilling. Such actions would likely result in the reduction of our PUDs and related PV-10 and a reduction in our ability to service our debt obligations. If we are required to further curtail our drilling program, we may be unable to continue to hold leases that are scheduled to expire, which may further reduce our reserves. As a result, if oil, natural gas and/or NGLs prices experience a sustained period of weakness, our future business, financial condition, results of operations, liquidity, and ability to finance planned capital expenditures may be materially and adversely affected.

The inability to renegotiate our transportation and marketing contracts may adversely affect our business and financial condition.

We enter into firm transportation, gas processing, gathering and compression service, water handling and treatment, or other agreements that require minimum volume delivery commitments in the normal course of our business. During the spring of 2020, in light of market conditions, we began renegotiating our transportation, gathering and marketing contracts to reduce, restructure or eliminate our minimum volume commitments to our transportation, gas processing and gathering and compression service providers. Any inability to renegotiate transportation and marketing contracts to reflect current market conditions increases our marketing and transportation costs, inclusive of costs related to unutilized transportation and/or processing capacity for previously planned volumes. Such increased costs decrease realized revenue at any notional commodity value, negatively impacting financial results, competitiveness, and our overall financial condition. If we are unable to modify our minimum volume commitments, we may not have sufficient production to fulfill them which would have an adverse effect on our business and financial condition.

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Failure to maintain the continued listing standards of NASDAQ could result in delisting of our common stock, which could negatively impact the market price and liquidity of our common stock and our ability to access the capital markets.

Our shares are listed on the NASDAQ Global Market (“NASDAQ”) and the continued listing of our shares on NASDAQ is subject to our ability to comply with NASDAQ’s continued listing requirements, including, among other things, a minimum closing bid price requirement of $1.00 per shares. On March 30, 2020, we received a letter from the Listing Qualifications Department of NASDAQ notifying us that our shares closed below the $1.00 per unit minimum bid price required by NASDAQ Listing Rule 5450(a)(1) for 30 consecutive business days and that we have a period of 180 calendar days in which to regain compliance.

We are considering options to regain compliance. If we are unable to regain compliance, however, any delisting from NASDAQ could result in even further reductions in our price per share, substantially limit the liquidity of our common stock, and materially adversely affect our ability to raise capital or pursue strategic restructuring, refinancing or other transactions on acceptable terms, or at all. Delisting from the NASDAQ could also have other negative results, including the potential loss of institutional investor interest and fewer business development opportunities.

There is no assurance that we will continue to maintain compliance with NASDAQ continued listing standards. Our business has been and may continue to be affected by worldwide macroeconomic factors, which include uncertainties in the credit and capital markets as well as with respect to commodity prices. External factors that affect our share price, such as liquidity requirements of our investors, as well as our performance, could impact our market capitalization, revenue and operating results, which, in turn, affect our ability to comply with the NASDAQ’s listing standards. The NASDAQ has the ability to suspend trading in our shares or remove our shares from listing on the NASDAQ if in the opinion of the exchange: (a) the financial condition and/or operating results of the Company appear to be unsatisfactory; (b) it appears that the extent of public distribution or the aggregate market value of our units has become so reduced as to make further dealings on the exchange inadvisable; (c) we have sold or otherwise disposed of our principal operating assets, or have ceased to be an operating company; (d) we have failed to comply with our listing agreements with the exchange; or (e) any other event shall occur or any condition shall exist which makes further dealings on the exchange unwarranted.

There is substantial risk that it may be necessary for us to seek protection under Chapter 11 of the United States Bankruptcy Code, which may have a material adverse impact on our business, financial condition, results of operations, and cash flows, would have a material adverse impact on the trading price of our securities, and could place our shareholders at significant risk of losing all of their investment in our shares.

We have engaged financial and legal advisors to assist us in, among other things, analyzing various strategic alternatives to address our liquidity and capital structure, including strategic and refinancing alternatives to restructure our indebtedness in private transactions. Due to our current financial constraints, there is a substantial risk that it may be necessary for us to seek protection under Chapter 11.

Seeking bankruptcy court protection could have a material adverse effect on our business, financial condition, results of operations and liquidity. As long as a Chapter 11 proceeding continues, our senior management would be required to spend a significant amount of time and effort dealing with the reorganization instead of focusing on our business operations. Bankruptcy court protection also may make it more difficult to retain management and other key personnel necessary to the success and growth of our business. In addition, during the period of time we are involved in a bankruptcy proceeding, our customers and suppliers might lose confidence in our ability to reorganize our business successfully and may seek to establish alternative commercial relationships.

Additionally, all of our indebtedness is senior to the existing common stock and preferred stock in our capital structure. As a result, we believe that seeking bankruptcy court protection under a Chapter 11 proceeding could cause the shares of our existing common stock to be canceled, result in a limited recovery, if any, for shareholders of our common stock, and would place shareholders of our common stock at significant risk of losing all of their investment in our shares.

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

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

We are providing the following disclosure in lieu of filing a Current Report on Form 8-K relating to “Item 5.02 Departure of Directors or Certain Officers; Election of Directors; Appointment of Certain Officers; Compensatory Arrangements” of Form 8-K.

On May 8, 2020, the Company entered into an Indemnification Agreement (the “Indemnification Agreement”) with Marianella Foschi. The Indemnification Agreement requires the Company to indemnify Ms. Foschi to the fullest extent permitted under Delaware law against liability that may arise by reason of her service to the Company, and to advance certain expenses incurred as a result of any proceeding against her as to which she could be indemnified.

The foregoing description of the Indemnification Agreement is not complete and is qualified in its entirety by reference to the full text of the Indemnification Agreement, which is attached as Exhibit 10.10 to this Current Report on Form 10-Q and incorporated into this Item 5 by reference.

ITEM 6. EXHIBITS

(a) Exhibits:

The exhibits listed on the accompanying Exhibit Index are filed, furnished or incorporated by reference as part of this report, and such Exhibit Index is incorporated herein by reference.

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INDEX TO EXHIBITS

Exhibit Number	Description
3.1	Certificate of Incorporation of Extraction Oil & Gas, Inc., dated October 11, 2016 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K (File No. 001-37907) filed with the Commission on October 14, 2016).
3.2	Certificate of Designations of Series A Preferred Stock of Extraction Oil & Gas, Inc., filed with the Secretary of State of the State of Delaware on October 17, 2016 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K (File No. 001-37907) filed with the Commission on October 21, 2016).
3.3	Bylaws of Extraction Oil & Gas, Inc., dated October 11, 2016 (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K (File No. 001-37907) filed with the Commission on October 14, 2016).
†10.1	Restricted Stock Unit Award Agreement (Thomas B. Tyree) (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (File No. 001-37907) filed with the Commission on March 5, 2020).
†10.2	Employment Agreement dated as of March 4, 2020, between the Company and Thomas B. Tyree (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K (File No. 001-37907) filed with the Commission on March 5, 2020).
†10.3	Indemnification Agreement (Thomas B. Tyree) (incorporated by reference to Exhibit 10.3 to the Company's Current Report on Form 8-K (File No. 001-37907) filed with the Commission on March 5, 2020).
†10.4	Amended and Restated Employment Agreement effective as of March 4, 2020, between the Company and Matt Owens (incorporated by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K (File No. 001-37907) filed with the Commission on March 5, 2020).
†10.5	Extraction Oil & Gas, Inc. Executive Severance Plan (incorporated by reference to Exhibit 10.5 to the Company’s Current Report on Form 8-K (File No. 001-37907) filed with the Commission on March 5, 2020).
†10.6	Form of Participation Agreement (Executive Severance Plan) (incorporated by reference to Exhibit 10.6 to the Company’s Current Report on Form 8-K (File No. 001-37907) filed with the Commission on March 5, 2020).
†10.7	Employment Transition Agreement, dated March 18, 2020, between Extraction Oil & Gas, Inc., XOG Services, LLC. and Mark A. Erickson (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (File No. 001-37907) filed with the Commission on March 20, 2020).
†10.8	Form of Restricted Stock Unit Award Agreement (Performance-Vesting, Share-Settled) (for Officers) (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K (File No. 001-37907) filed with the Commission on March 20, 2020).
†10.9	Form of Restricted Cash Award Agreement (Employees) (incorporated by reference to Exhibit 10.3 to the Company’s 8-K (File No. 001-37907) filed with the Commission on March 20, 2020).
*†10.10	Indemnification Agreement (Marianella Foschi)
*31.1	Certification of Chief Executive Officer required by Rules 13a-14 and 15d-14 under the Securities Exchange Act of 1934.
*31.2	Certification of Chief Financial Officer required by Rules 13a-14 and 15d-14 under the Securities Exchange Act of 1934.
**32.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
**32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*101	Interactive Data Files
†	Management contract or compensatory plan or agreement.
*	Filed herewith.
**	Furnished herewith.

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SIGNATURES

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

Date: May 11, 2020.

Extraction Oil & Gas, Inc.
By:	/S/ MATTHEW R. OWENS
	Matthew R. Owens
	President and Chief Executive Officer (principal executive officer)

By:	/S/ TOM L. BROCK
	Tom L. Brock
	Vice President and Chief Accounting Officer (principal financial officer)

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