~~THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF~~

~~THESE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

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	$	—

For the Nine Months Ended September 30,
2017 2016
Cash flows from operating activities:
Net loss $ (13,840 ) $ (210,400 )
Reconciliation of net loss to net cash provided by operating activities:
Depletion, depreciation, amortization and accretion 213,483
141,317
Abandonment and impairment of unproved properties 5,684
3,331
Impairment of long lived assets 675
23,350
Loss on sale of property and equipment 451
—
Amortization of debt issuance costs and debt discount 3,181
18,330
Deferred rent (229 ) 600
Commodity derivatives (gain) loss (46,423 ) 62,424
Settlements on commodity derivatives (8,893 ) 43,015
Premiums paid on commodity derivatives —
(611 )
Earnings in unconsolidated affiliate (256 ) —
Distributions from unconsolidated affiliate 131
—
Deferred income tax expense (7,556 ) —
Unit and stock-based compensation 46,707
14,922
Changes in current assets and liabilities:
Accounts receivable—trade (29,099 ) 3,889
Accounts receivable—oil, natural gas and NGL sales (36,359 ) (8,506 )
Inventory and prepaid expenses (180 ) (273 )
Accounts payable and accrued liabilities 1,653
(18,242 )
Revenue payable 6,047
10,228
Production taxes payable 13,520
6,219
Accrued interest payable (5,553 ) 8,342
Asset retirement expenditures (1,408 ) (372 )
Net cash provided by operating activities 141,736
97,563
Cash flows from investing activities:
Oil and gas property additions (1,015,700 ) (223,684 )
Acquired oil and gas properties (17,225 ) (13,674 )
Sale of property and equipment 5,155
2,148
Other property and equipment additions (9,608 ) (3,336 )
Distributions from unconsolidated affiliate, return of capital 116
—
Cash held in escrow 42,200
(42,000 )
Net cash used in investing activities (995,062 ) (280,546 )
Cash flows from financing activities:
Borrowings under credit facility 250,000
60,000
Repayments under credit facility (250,000 ) (196,000 )
Proceeds from the issuance of Senior Notes 394,000
550,000
Repayment of Second Lien Notes —
(430,000 )
Proceeds from the issuance of units —
121,370
Repurchase of units —
(2,867 )
Payment of employee payroll withholding taxes (2,832 ) —
Dividends on Series A Preferred Stock (7,680 ) —
Debt issuance costs (3,273 ) (13,189 )
Equity issuance costs (1,486 ) (2,051 )
Net cash provided by financing activities 378,729
87,263
Decrease in cash and cash equivalents (474,597 ) (95,720 )
Cash and cash equivalents at beginning of period 588,736
97,106
Cash and cash equivalents at end of the period $ 114,139
$ 1,386
Supplemental cash flow information:
Property and equipment included in accounts payable and accrued liabilities $ 130,022
$ 53,371
Cash paid for interest $ 44,703
$ 30,531
Cash paid for Second Lien Notes prepayment penalty $ —
$ 4,300
Noncash settlement of promissory notes issued to officers $ —
$ 5,562
Accretion of beneficial conversion feature of Series A Preferred Stock $ 3,992
$ —
Non-cash contribution to unconsolidated affiliate $ 8,307
$ —
Increase in dividends payable $ 484
$ —

THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF

THESE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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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

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EXTRACTION OIL & GAS, INC.

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 1—Business and Organization

Extraction Oil & Gas, Inc. (the ~~“Company”~~"Company" or ~~“Extraction”~~"Extraction") is an independent oil and gas company focused on the acquisition, development and production of oil, natural gas and ~~NGL~~natural gas liquids (“NGLs”) reserves in the Rocky Mountain region, primarily in the Wattenberg Field of the Denver-Julesburg Basin (the ~~“DJ Basin”~~"DJ Basin") of ~~Colorado. The Company and its subsidiaries are focused on the acquisition, development and production of oil, natural gas and NGL reserves in the Rocky Mountain region,~~Colorado, as well as the ~~design~~construction and support of midstream assets to gather and process crude oil and gas ~~production focused in the DJ Basin of Colorado.~~production. Extraction is a public company listed for trading on the NASDAQ Global Select Market under the symbol ~~“XOG”.~~"XOG."

~~The~~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 ~~financial~~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 ~~and nine~~ months ended ~~September 30, 2016 are based on the financial statements~~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 ~~Company’s accounting predecessor,~~abandonment of certain projects. In accordance with Accounting Standards Codification Topic 323-10-35-20: Investments—equity method and joint ventures, Extraction ~~Oil & Gas Holdings, LLC, prior~~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 ~~the corporate reorganization~~certain of Elevation's members other than Extraction (the ~~“Corporate Reorganization”~~"Capital Raise")~~, pursuant~~. The Capital Raise caused Extraction's ownership of Elevation to ~~which, in connection with the initial public offering~~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 ~~(the "IPO"), (i) on October 11, 2016, a former subsidiary~~reserves all rights related to actions taken by Elevation’s board of Extraction Oil & Gas Holdings, LLC, Extraction Oil & Gas, LLC, converted into the Company, and (ii) on October 17, 2016, Holdings merged with and into the Company with the Company as the surviving entity. For further information on the Corporate Reorganization please refer to the Company’s Annual Report.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

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statements and the year-end balance ~~sheet~~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.~~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

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

Recent Accounting Pronouncements

In ~~May 2017,~~June 2016, the Financial Accounting Standards Board ~~(“FASB”~~("FASB") issued Accounting Standards Update ~~(“ASU”~~("ASU") No. ~~2017-09, which provides clarification~~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 ~~reduces both (1) diversity in practice~~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 ~~(2)~~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 ~~complexity when applying~~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 ~~in Topic 718 Compensation - Stock Compensation, to~~is effective. The Company adopted this ASU on January 1, 2020, and the adoption did not have a ~~change~~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 ~~terms~~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 ~~conditions of a share-based payment award.~~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, ~~2017,~~2019, including interim reporting periods within that reporting period. Early adoption is permitted for fiscal years beginning after December 15, 2016, including the interim reporting periods within that fiscal year. The Company is currently evaluating the impact of adopting this ASU, however it is not expected to have a significant effect on its consolidated financial statements.

In February 2017, the FASB issued ASU No. 2017-05, which provided clarification regarding the guidance on accounting for the derecognition of nonfinancial assets. For public entities, the new guidance is effective for fiscal years beginning after December 15, 2017, including interim reporting periods within that fiscal year. The Company is currently evaluating this new standard to determine the potential impact to its financial statements and related disclosures.

In January 2017, the FASB issued ASU No. 2017-04, which simplifies how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. Step 2 measures a goodwill impairment loss by comparing the implied fair value of a reporting unit’s goodwill with the carrying amount. For public entities, the new guidance is effective for fiscal years beginning after December 15, 2019. Early adoption is permitted for interim and annual goodwill impairment tests performed on testing dates after January 1, 2017. The Company is currently evaluating this ASU and believes it could have a material impact to its financial statements and related disclosures.

In January 2017, the FASB issued ASU No. 2017-01, which clarifies the definition of a business when evaluating whether transactions should be accounted for as acquisitions or disposals of assets or businesses. For public entities, the new guidance is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted for transactions for which the acquisition date occurs before the issuance date or effective date of the amendments, only when the transaction has not been reported in the financial statements that have been issued. The Company is currently evaluating this ASU and believes it could have a material impact to its financial statements and related disclosures.

In November 2016, the FASB issued ASU No. 2016-18, which intends to clarify how entities should present restricted cash and restricted cash equivalents in the statement of cash flows. This amendment will be effective retrospectively for reporting periods beginning after December 15, 2017, and early adoption is permitted. The Company is currently evaluating the impact of adopting this ASU, however it is not expected to have a significant effect on its consolidated financial statements.

In August 2016, the FASB issued ASU No. 2016-15, which addresses eight specific cash flow issues, including presentation of debt prepayments or debt extinguishment costs, with the objective of reducing the existing diversity in practice. In addition, in November 2016, the FASB issued ASU No. 2016-18, which requires that amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. For public entities, the new guidance is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. The Company is currently evaluating this ASU to determine the potential impact to its financial statements and related disclosures.

In March 2016, the FASB issued ASU No. 2016-06, which clarifies the requirements to assess whether an embedded put or call option is clearly and closely related to the debt host, solely in accordance with the four step decision sequence in FASB ASB Topic 815, Derivatives and Hedging, as amended by this ASU. This standard is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016 and should be applied using a modified retrospective approach. The Company adopted this ASU ~~in the first quarter of 2017 and the adoption of this ASU~~on January 1, 2020 which did not have a material impact on the ~~its consolidated financial statements.~~

In February 2016, the FASB issued ASU No. 2016-02, which requires lessee recognition on the balance sheet of a right of use asset and a lease liability, initially measured at the present value of the lease payments. It further requires recognition in the income statement of a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a generally straight line basis. Finally, it requires classification of all cash payments within operating activities in the statements of cash flows. It is effective for fiscal years commencing after December 15, 2018 and early adoption is permitted. In September 2017, the FASB issued ASU No. 2017-13, which provided additional implementation guidance. The Company is currently evaluating the impact this ASU will have on its financial statements and related disclosures and developing a strategy for implementation.

In May 2014, the FASB issued ASU No. 2014-09, which establishes a comprehensive new revenue recognition model designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. The ASU allows for the use of either the full or modified retrospective transition method. In August 2015, the FASB issued ASU No. 2015-14, which deferred ASU No. 2014-09 for one year, and is effective for annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. Earlier application is permitted only as of reporting periods beginning after December 15, 2016. The FASB subsequently issued ASU No. 2016-08, ASU No. 2016-10, ASU No. 2016-11, ASU No. 2016-12, ASU No. 2016-20, and ASU No. 2017-13, which provided additional implementation guidance. The Company is in the final stages of its review of contracts in each of its revenue streams and has developed accounting policies to address the provisions of this ASU. While the Company does not expect operating income (loss) to be materially impacted, the Company does expect total revenues and total expenses to change as a result of certain percentage of proceeds contracts. Further, the Company has begun evaluating the design of its pre-adoption and adoption controls and expects new or modification of certain controls to address risks associated with recognizing revenue under the new standard as we continue the implementation process. The Company will continue to evaluate the impact of this and other provisions of the ASU on its accounting policies, internal controls, and consolidated financial statements and related disclosures ~~and has~~as capitalized costs for internal-use software were not ~~finalized any estimates~~material as of ~~the potential impacts. The Company will~~March 31, 2020.

~~adopt this new standard on January 1, 2018, using the modified retrospective method with a cumulative adjustment to retained earnings.~~

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 through the date of this filing.~~Company.

Note 3—~~Acquisitions~~Divestitures

~~July 2017 Acquisition~~February 2020 Divestiture

~~On July 7, 2017,~~In February 2020, the Company ~~acquired an unaffiliated oil and gas company’s interests in approximately 12,500 net acres~~completed the sale of ~~leasehold, and primarily non-producing properties and~~certain non-operated producing properties ~~located primarily in Adams County, Colorado, along with various other related rights, permits, contracts, equipment, rights~~for aggregate sales proceeds of ~~way, gathering systems and other assets (the "July 2017 Acquisition"). Upon closing the seller received total consideration of $84.0~~approximately $12.2 million, ~~in cash,~~ 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.

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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 ~~July 2017 Acquisition is~~March 2019 Divestiture was July 1, ~~2017. This transaction has been accounted for as an asset acquisition. The acquisition provides new development opportunities in the DJ Basin.~~

~~June 2017 Acquisition~~

On June 8, 2017, the Company acquired an unaffiliated oil and gas company’s interests in approximately 160 net acres of leasehold and related producing properties located in Weld County, Colorado (the “June 2017 Acquisition”). The Company paid approximately $13.4 million in cash consideration in connection with the closing of the June 2017 Acquisition. The effective date for the acquisition was January 1, 2017,2018 with purchase price adjustments calculated as of the closing date of ~~June 8, 2017. The acquisition increased the Company's interest~~$5.9 million, resulting in ~~existing operated wells. The acquired producing properties contributed $1.5 million and $2.2 million~~net proceeds of ~~revenue and $1.1 million and $1.7 million of earnings, respectively, for three and nine months ended September 30, 2017. The acquired producing properties contributed de minimis revenue and earnings~~$16.5 million. No gain or loss was recognized for the ~~three~~March 2019 Divestiture.

Note 4—Going Concern

The Company depends on cash flows from operating activities and, ~~nine months ended September 30, 2016. No significant transaction costs related~~as necessary and available, borrowings under its senior secured revolving credit facility (the “revolving credit facility”) to ~~the acquisition were incurred for the three~~fund its capital expenditures and ~~nine months ended September 30, 2017 and 2016.~~

~~The June 2017 Acquisition was accounted for using the acquisition method under ASC 805,~~ ~~Business Combinations, which requires the acquired assets and liabilities to be recorded at fair value as of the acquisition date of June 8, 2017. In August 2017,~~working capital requirements. Additionally, the Company completed the transaction’s post-closing settlement. The following table summarizes the purchase price and the final allocation of the fair values of assets acquired and liabilities assumed (in thousands):

Purchase Price June 8, 2017
Consideration given
Cash $ 13,395
Total consideration given $ 13,395
Allocation of Purchase Price
Proved oil and gas properties $ 13,495
Total fair value of oil and gas properties acquired $ 13,495
Asset retirement obligations $ (100 )
Fair value of net assets acquired $ 13,395

~~November 2016 Acquisition~~

On November 22, 2016, the Company acquired an unaffiliated oil and gas company’s interest in approximately 9,200 net acres of unproved leaseholds located in the DJ Basin for approximately $120.0 million, including customary closing adjustments (the “November 2016 Acquisition”). This transactionhistorically has been accounted for as an asset acquisition. The Company also made a $41.1 million deposit in November 2016 in conjunction with November 2016 Acquisition, which has been reflected in the December 31, 2016 consolidated balance sheet within the cash held in escrow line item. The deposit was made for two additional closings of leaseholds located in the DJ Basin. The first closing occurred in January 2017 and added approximately 5,300 net acres for approximately $26.8 million. The second closing occurred in July 2017 and added approximately 640 net acres for approximately $10.9 million.

~~October 2016 Acquisition~~

On October 3, 2016, the Company acquired an unaffiliated oil and gas company’s interests in approximately 6,400 net acres of leasehold, and related producing and non‑producing properties located primarily in Weld County, Colorado, along with various other related rights, permits, contracts, equipment, rights of way, gathering systems and other assets (the “October 2016 Acquisition” or the “Bayswater Acquisition”). The seller received aggregate consideration of approximately $405.3 million in cash. The effective date for the acquisition was July 1, 2016, with purchase price adjustments calculated as of the closing date on October 3, 2016. The acquisition provides new development opportunities in the DJ Basin as well as increases the Company’s existing working interest, as the majority of the locations are located on acreage in which the Company already owns a majority working interest and operates. The Company incurred $2.6 million of transaction costs related to the acquisition. These transaction costs were recorded in the condensed consolidated statements of operations within the acquisition transaction expenses line item, $0.3 million in transaction costs related to the acquisition were incurred for the three and nine months ended September 30, 2016. No transaction costs related to the acquisition were incurred for the three and nine months ended September 30, 2017.

~~The acquisition is accounted for using the acquisition method under ASC 805,~~ ~~Business Combinations~~, which requires the acquired assets and liabilities to be recorded at fair value as of the acquisition date of October 3, 2016. In February 2017, the Company completed the transaction’s post-closing settlement. The following table summarizes the purchase price and the final allocation of the fair values of assets acquired and liabilities assumed (in thousands):

Purchase Price October 3, 2016
Consideration given
Cash $ 405,335
Total consideration given $ 405,335
Allocation of Purchase Price
Proved oil and gas properties $ 252,522
Unproved oil and gas properties 109,800
Total fair value of oil and gas properties acquired $ 362,322
Goodwill ⁽¹⁾
$ 54,220
Working capital (7,185 )
Asset retirement obligations (4,022 )
Fair value of net assets acquired $ 405,335
Working capital acquired was estimated as follows:
Accounts receivable $ 955
Revenue payable (3,012 )
Production taxes payable (4,244 )
Accrued liabilities (884 )
Total working capital $ (7,185 )


~~(1)~~	~~Goodwill is primarily attributable to a decrease in commodity prices~~used proceeds from the time the acquisition was negotiated to commodity prices on October 3, 2016 and the operational and financial synergies expected to be realized from the acquisition. Goodwill recognized as a result of the Bayswater Acquisition is not deductible for income tax purposes.

~~August 2016 Acquisition~~

On August 23, 2016, the Company acquired an unaffiliated oil and gas company’s interests in approximately 1,400 net acres of leasehold located primarily in Weld County, Colorado, along with various other related rights, permits, contracts, equipment, rights of way and other assets (the “August 2016 Acquisition”). The seller received aggregate consideration of approximately $17.5 million in cash. The effective date for the acquisition was August 31, 2016, with purchase price adjustments calculated as of the closing date of August 23, 2016. The acquisition provided new development opportunities in the DJ Basin as well as additions adjacent to the Company’s core project area. The Company incurred $0.1 million of transaction costs related to the acquisition. These transaction costs were recorded in the condensed consolidated statements of operations within the acquisition transaction expenses line item in the third quarter of 2016.

~~The acquisition was accounted for using the acquisition method under ASC 805,~~ ~~Business Combinations~~, which requires the acquired assets and liabilities to be recorded at fair value as of the acquisition date of August 23, 2016. In March 2017, the Company completed the transaction’s post-closing settlement. The following table summarizes the purchase price and the final allocation of the fair values of assets acquired and liabilities assumed (in thousands):

Purchase Price August 23, 2016
Consideration given
Cash $ 17,504
Total consideration given $ 17,504
Allocation of Purchase Price
Proved oil and gas properties $ 12,362
Unproved oil and gas properties 8,566
Total fair value of oil and gas properties acquired $ 20,928
Working capital $ (9 )
Asset retirement obligations (3,415 )
Fair value of net assets acquired $ 17,504
Working capital acquired was estimated as follows:
Production taxes payable $ (9 )
Total working capital $ (9 )

~~Pro Forma Financial Information (Unaudited)~~

For the three and nine months ended September 30, 2016, the following pro forma financial information represents the combined results for the Company and the properties acquired in October 2016 as if the acquisition and related financing had occurred on January 1, 2016. For purposes of the pro forma financial information, it was assumed that the October 2016 Acquisition was funded through the issuance of ~~$260.3~~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 ~~in convertible preferred securities~~from $950.0 million on April 27, 2020, and ~~borrowings~~the Company borrowed all of its remaining available capacity under the revolving credit facility. The pro forma information includes the effects of adjustments for depletion, depreciation, amortization and accretion ("DD&A") expense of $9.0 million and $23.1 million for the three and nine months ended September 30, 2016, respectively. No pro forma adjustments were made for the effect of income taxes for the three and nine months ended September 30, 2016 as the acquisitions occurred before the Corporate Reorganization. The October 2016 Acquisition was included in the historical resultsAs a result of the ~~Company for~~reduction of the ~~three~~borrowing base and nine months ended September 30, 2017, therefore this acquisition has no impact on the pro forma financial information for the three and nine months ended September 30, 2017. Additionally, the pro forma financial information excludes the effects the August 2016 Acquisition as these pro forma adjustments were de minimis. For the three and nine months ended September 30, 2017, the following pro forma financial information represents the combined results forelected commitments, it is probable that the Company ~~and~~will not meet the ~~properties acquired in~~financial covenants under the June 2017 Acquisition as if the acquisition had occurred on January 1, 2016. The June 2017 Acquisition has no impact on the historical results of the Company for the three and nine months ended September 30, 2016. For purposes of pro forma financial information, it was assumed that the June 2017 Acquisition was funded through cash. The pro forma financial information had no adjustments for DD&A expense and no adjustments for income tax expenserevolving credit facility for the three months ended ~~September~~June 30, ~~2017~~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 ~~this was included~~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 ~~condensed~~normal course of business. The consolidated financial ~~results. For~~statements do not reflect any adjustments that might result if the ~~nine months ended September 30, 2017, the pro forma financial information includes effects~~Company is unable to continue as a going concern.

Table of adjustments for DD&A expense of $1.6 million. The pro forma financial information also includes the effects of adjustments for income tax expense of $0.6 million for the nine months ended September 30, 2017.Contents

Note 5—Long-Term Debt

The following pro forma results (in thousands, except per share data) do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the properties acquired. Asset acquisitions are not included in pro forma financial information, as it is not required. The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of the period, nor are they necessarily indicative of future results. Net loss per common share is not applicable for the period prior to the Corporate Reorganization.

For the Three Months Ended September 30, For the Nine Months Ended September 30,
2017 2016 2017 2016
Revenues $ 180,861
$ 92,476
$ 392,430
$ 230,665
Operating expenses $ 175,699
$ 106,765
$ 427,912
$ 304,677
Net loss $ (29,796 ) $ (30,268 ) $ (13,663 ) $ (197,254 )
Loss per common share, basic and diluted $ (0.20 ) $ (0.15 )

~~Note 4—Long‑Term Debt~~

~~As of the dates indicated, the~~ Company’s ~~long‑term~~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

September 30,
2017 December 31,
2016
Credit facility due August 16, 2022 (or an earlier time as set forth in the credit facility) $ —
$ —
2021 Senior Notes due July 15, 2021 550,000
550,000
2024 Senior Notes due May 15, 2024 400,000
—
Unamortized debt issuance costs on Senior Notes (17,430 ) (11,859 )
Total long-term debt 932,570
538,141
Less: current portion of long-term debt —
—
Total long-term debt, net of current portion $ 932,570
$ 538,141

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) ~~January 15, 2021 if (and only if) the Company's 2021 Senior Notes (as defined below) have not been refinanced or repaid in full on or prior to January 15, 2021, (c)~~ April 15, 2021, if (and only if) (i) the Series A Preferred Stock ~~of the Company (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 ~~(d)~~(c) the earlier termination in whole of the ~~commitments.~~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 ~~September 30, 2017,~~March 31, 2020, the credit facility ~~was~~had a maximum credit amount of $1.5 billion, subject to a borrowing base and elected commitments of ~~$375.0~~$950.0 million. As of ~~September 30, 2017~~March 31, 2020 and ~~with respect to the Prior Credit Facility,~~ December 31, ~~2016,~~2019, the Company had no outstanding ~~borrowings. As~~borrowings of ~~September 30, 2017~~$470.0 million and ~~with respect to the Prior Credit Facility, December 31, 2016, the Company~~ had standby letters of credit of ~~$25.7~~$49.5 million ~~and $0.6 million, respectively.~~which reduces the availability of the undrawn borrowing base. At ~~September 30, 2017,~~March 31, 2020, the undrawn balance under the credit facility was ~~$375.0~~$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 ~~Company had no borrowings outstanding~~available balance under the credit ~~facility.~~facility was 0.

~~Redetermination of~~Principal amounts borrowed on the ~~borrowing base was scheduled~~credit facility will be payable on ~~August 1, 2017 and semiannually on May 1 and November 1, thereafter. The Company and~~ the ~~administrative agent~~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 ~~each elect a redetermination~~be re-borrowed from time to time, subject to the terms of the ~~borrowing base between any two scheduled redeterminations. The scheduled August 1, 2017 redetermination closed in October 2017, resulting in a borrowing base increase to $525.0 million.~~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	%

Borrowing Base Utilization Percentage Utilization
Eurodollar
Margin

Base Rate
Margin

Commitment
Fee Rate
Level 1 < 25% 2.00% 1.00% 0.375%
Level 2 ≥ 25% < 50% 2.25% 1.25% 0.375%
Level 3 ≥ 50% < 75% 2.50% 1.50% 0.500%
Level 4 ≥ 75% < 90% 2.75% 1.75% 0.500%
Level 5 ≥ 90% 3.00% 2.00% 0.500%

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; and (v) holding cash balances in excess of certain thresholds while carrying a balance on the credit facility.~~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 ~~consolidated~~restricted subsidiaries’ current assets (includes availability under the revolving credit facility and unrestricted cash and excludes derivative assets) to its ~~consolidated~~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 ~~consolidated~~its restricted subsidiaries’ debt less cash balances to its ~~consolidated~~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 ~~items including DD&A, exploration~~charges and income (such as stock-based compensation expense, unrealized gains/losses on ~~derivative instruments, amortization~~commodity derivatives and impairment of ~~certain debt issuance costs, non-cash compensation expense, interest expense~~long-lived assets and ~~prepayment premiums on extinguishment of debt)~~goodwill), subject to pro forma adjustments for non-ordinary course acquisitions and divestitures) for the four fiscal quarter ~~period~~periods most recently ended, of not greater than ~~4.0:1.0. For the quarter ending September 30, 2017, consolidated EBITDAX will be based on~~4.0 to 1.0 as of the last six months’ consolidated EBITDAX multiplied by 2; and for the quarter ending December 31, 2017, consolidated EBITDAX will be based on the last nine months’ consolidated EBITDAX multiplied by 4/3. For the quarters ending on or afterday of such fiscal quarter. As of March 31, ~~2018, consolidated EBITDAX will be based on~~2020, the ~~last twelve months’ consolidated EBITDAX. The~~ Company was in compliance with ~~all~~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 asfor 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 ~~September~~its financial covenants for the three months ended June 30, ~~2017~~2020, the lenders under the revolving credit facility will be able to declare all outstanding principal and ~~through~~interest to be due and payable, and the ~~filing~~lenders under the credit agreement could terminate their commitments to loan money and could foreclose against the assets collateralizing their borrowings. Any acceleration of ~~this report.~~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 ~~the~~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.

~~2021 Senior Notes~~

~~In July 2016,~~ Elevation is an unrestricted subsidiary, which is no longer consolidated or controlled by the Company, ~~issued at par $550.0 million principal amount of 7.875% Senior Notes due July 15, 2021 (the “2021 Senior Notes”~~ and the ~~offering,~~assets and credit of Elevation are not available to satisfy the “2021 Senior Notes Offering”). The 2021 Senior Notes bear an annual interest rate of 7.875%. The interest on the 2021 Senior Notes is payable on January 15 and July 15 of each year commencing on January 15, 2017. The Company received net proceeds of approximately $537.2 million after deducting discounts and fees.

The 2021 Senior Notes are the Company's 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 2021 Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by each of the Company's current and future restricted subsidiaries (other than Extraction Finance Corp., the co-issuer of the 2021 Senior Notes) that guarantees its indebtedness under a credit facility (the “Guarantors”). The notes are effectively subordinated to all of the Company's secured indebtedness (including all

~~borrowings~~debts and other obligations ~~under its revolving credit facility) to the extent~~ of the ~~value~~Company or its other subsidiaries.

Table 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 future subsidiaries that do not guarantee the notes.Contents

The 2021 Senior Notes also contain affirmative and negative covenants that, among other things, limit the Company's and the 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 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 2021 Senior Notes (the “2021 Senior Notes Indenture”) also contains customary events of default. Upon the occurrence of events of default arising from certain events of bankruptcy or insolvency, the 2021 Senior Notes shall become due and payable immediately without any declaration or other act of the trustee or the holders of the 2021 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 2021 Senior Notes may declare all outstanding 2021 Senior Notes to be due and payable immediately. The Company was in compliance with all financial covenants under the 2021 Senior Notes Indenture as of September 30, 2017, and through the filing of this report.

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~~"2024 Senior ~~Notes”~~Notes" and the offering, the ~~“2024~~"2024 Senior Notes ~~Offering”~~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 ~~commencing~~which commenced on November 15, 2017. The Company received net proceeds of approximately $392.6 million after deducting ~~discounts and~~ 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 ~~each~~certain of ~~its~~the Company's current subsidiaries and by certain future restricted subsidiaries that guarantees its indebtedness under a credit facility (the ~~“2024~~"2024 Senior ~~Note Guarantors”~~Notes Guarantors"). The ~~notes~~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 ~~notes.~~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 ~~(the “2024 Senior Notes Indenture”)~~ 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. ~~The~~

2026 Senior Notes

In January 2018, the Company ~~was in compliance~~issued at par $750.0 million principal amount of 5.625% Senior Notes due February 1, 2026 (the "2026 Senior Notes" and together with ~~all financial covenants under~~ the 2024 Senior Notes, ~~Indenture through~~ the ~~filing~~"Senior Notes" and the offering of ~~this report.~~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 ~~September 30, 2017,~~March 31, 2020, the Company had debt issuance costs, net of accumulated amortization, of ~~$3.1~~$2.2 million related to its credit facility which has been reflected on the ~~Company’s~~Company's condensed consolidated balance ~~sheet~~sheets within the line item other ~~non‑current~~non-current assets. As of ~~September 30, 2017,~~March 31, 2020, the Company had debt issuance costs net of accumulated amortization of ~~$17.4~~$13.8 million related to its ~~2021~~2024 and ~~2024~~2026 Senior Notes ~~(collectively, the "Senior Notes")~~ which ~~has~~have been reflected on the Company's condensed consolidated balance ~~sheet~~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 ~~2021 Senior Notes~~ and ~~2024~~ Senior Notes. For the three ~~and nine~~ months ended ~~September 30, 2017, the Company recorded~~

~~amortization expense related to debt issuance costs of $1.5 million~~March 31, 2020 and $3.2 million, respectively as compared to $11.6 million and $13.5 million for the three and nine months ended September 30, 2016, respectively. Debt issuance costs for the three and nine months ended September 30, 2016 include $10.8 million of acceleration of amortization expense upon the repayment of the Company's Second Lien Notes. For additional information regarding amortization expense on Second Lien Notes, see the Company's Annual Report.

~~Debt Discount Costs on Second Lien Notes~~

~~For the three and nine months ended September 30, 2016,~~March 31, 2019, the Company recorded amortization expense related to the debt ~~discount on its Second Lien Notes~~issuance costs of ~~$4.3~~$1.2 million and ~~$4.8~~$1.5 million, respectively. The Company recorded no amortization expense related to the debt discount on its Second Lien Notes for the three and nine months ended September 30, 2017. For additional information regarding debt discount costs on Second Lien Notes, see the Company’s Annual Report.

Interest Incurred on ~~Long‑Term~~Long-Term Debt

For the three ~~and nine~~ months ended ~~September 30, 2017,~~March 31, 2020, the Company incurred interest expense on ~~long‑term~~long-term debt of ~~$16.5~~$22.3 million ~~and $39.2 million, respectively,~~ as compared to ~~$12.2 million and $38.9~~$20.8 million for the three ~~and nine~~ months ended ~~September 30, 2016, respectively.~~March 31, 2019. For the three ~~and six~~ months ended ~~September 30, 2017,~~March 31, 2020, the Company capitalized interest expense on long term debt of ~~$2.9~~$2.1 million ~~and $8.6 million, respectively,~~ as compared to ~~$1.2 million and $3.6~~$2.0 million for the three ~~and nine~~ months ended ~~September 30, 2016, respectively,~~March 31, 2019, which has been reflected in the Company’s ~~condensed~~ consolidated financial statements. ~~Also included~~

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 ~~interest~~connection with the Senior Notes Repurchase Program. Interest expense for the three ~~and nine~~ months ended ~~September 30, 2016 is~~March 31, 2019 included a ~~prepayment penalty of $4.3~~$7.3 million gain on debt repurchase related to the Company's ~~repayment of its Second Lien Notes in July 2016.~~Senior Note Repurchase Program.

Note 5—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 ~~six counterparties.~~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 ~~are no~~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 ~~September 30, 2017~~March 31, 2020 are summarized below:


										2020		2021		2022		2023
	2017			2018			2019
NYMEX WTI⁽¹⁾ Crude Swaps:
NYMEX WTI Crude Swaps:									NYMEX WTI Crude Swaps:
Notional volume (Bbl)	1,850,000			5,100,000			—		Notional volume (Bbl)	2,800,000		4,200,000		1,020,000		900,000
Weighted average fixed price ($/Bbl)	$	50.64		$	51.61				Weighted average fixed price ($/Bbl)	$	59.75	$	57.10	$	54.84	$	54.87
NYMEX WTI⁽¹⁾ Crude Sold Calls:
NYMEX WTI Crude Purchased Puts:									NYMEX WTI Crude Purchased Puts:
Notional volume (Bbl)									Notional volume (Bbl)	5,300,000		3,600,000		—		—
Weighted average purchased put price ($/Bbl)									Weighted average purchased put price ($/Bbl)	$	54.83	$	54.17	$	—	$	—
NYMEX WTI Crude Purchased Calls:									NYMEX WTI Crude Purchased Calls:
Notional volume (Bbl)									Notional volume (Bbl)	250,000		—		—		—
Weighted average purchased call price ($/Bbl)									Weighted average purchased call price ($/Bbl)	$	57.06	$	—	$	—	$	—
NYMEX WTI Crude Sold Calls:									NYMEX WTI Crude Sold Calls:
Notional volume (Bbl)	1,200,000			6,190,000			3,000,000		Notional volume (Bbl)	6,250,000		3,600,000		—		—
Weighted average sold call price ($/Bbl)	$	53.04		$	55.75		$	55.10	Weighted average sold call price ($/Bbl)	$	61.94	$	61.93	$	—	$	—
NYMEX WTI⁽¹⁾ Crude Sold Puts:
NYMEX WTI Crude Sold Puts:									NYMEX WTI Crude Sold Puts:
Notional volume (Bbl)	3,225,000			11,338,800			3,000,000		Notional volume (Bbl)	8,100,000		7,800,000		600,000		600,000
Weighted average sold put price ($/Bbl)	$	37.19		$	38.93		$	39.70	Weighted average sold put price ($/Bbl)	$	43.08	$	43.27	$	43.00	$	43.00
NYMEX WTI⁽¹⁾ Crude Purchased Puts:
Notional volume (Bbl)	1,800,000			6,838,800			3,000,000
Weighted average purchased put price ($/Bbl)	$	42.13		$	47.35		$	49.37
NYMEX HH⁽²⁾ Natural Gas Swaps:
NYMEX HH Natural Gas Swaps:									NYMEX HH Natural Gas Swaps:
Notional volume (MMBtu)	7,420,000			37,200,000			—		Notional volume (MMBtu)	27,000,000		—		—		—
Weighted average fixed price ($/MMBtu)	$	3.06		$	3.10				Weighted average fixed price ($/MMBtu)	$	2.75	$	—	$	—	$	—
NYMEX HH⁽²⁾ Natural Gas Purchased Puts:
Notional volume (MMBtu)	—			2,400,000			—
Weighted average purchased put price ($/MMBtu)				$	3.00
NYMEX HH⁽²⁾ Natural Gas Sold Calls:
Notional volume (MMBtu)	—			2,400,000			—
Weighted average sold call price ($/MMBtu)				$	3.15
CIG⁽³⁾ Basis Gas Swaps:
CIG Basis Gas Swaps:									CIG Basis Gas Swaps:
Notional volume (MMBtu)	5,215,000			6,300,000			—		Notional volume (MMBtu)	34,200,000		2,400,000		—		—
Weighted average fixed basis price ($/MMBtu)	$	(0.31	)	$	(0.31	)			Weighted average fixed basis price ($/MMBtu)	$	(0.61)	$	(0.57)	$	—	$	—


~~(1)~~	~~NYMEX WTI refers to West Texas Intermediate crude oil price on the New York Mercantile Exchange.~~


~~(2)~~	~~NYMEX HH refers to the Henry Hub natural gas price on the New York Mercantile Exchange.~~


~~(3)~~	~~CIG refers to the NYMEX HH settlement price less the fixed basis price, the Rocky Mountains (CIGC) settlement price.~~

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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As of September 30, 2017
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 $ 25,250
$ (24,264 ) $ 986
$ (146 ) $ 840
Non-current assets $ 25,141
$ (25,141 ) $ —
$ —
$ —
Current liabilities $ (32,523 ) $ 24,264
$ (8,259 ) $ 146
$ (11,138 )
Non-current liabilities $ (28,166 ) $ 25,141
$ (3,025 ) $ —
$ —

As of December 31, 2016
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 $ 12,620
$ (12,620 ) $ —
$ —
$ —
Non-current assets $ 14,993
$ (14,993 ) $ —
$ —
$ —
Current liabilities $ (68,623 ) $ 12,620
$ (56,003 ) $ —
$ (62,741 )
Non-current liabilities $ (21,731 ) $ 14,993
$ (6,738 ) $ —
$ —


~~(1)~~	Agreements are in place with all of the Company’s financial trading counterparties 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 item and all counterparties in a net liability position are shown in the current liability line item.

(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 ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2020 and ~~2016~~2019 (in thousands). Commodity derivatives gain (loss) isare 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)

For the Three Months Ended September 30, For the Nine Months Ended September 30,
2017 2016 2017 2016
Commodity derivatives gain (loss) $ (37,875 ) $ 16,225
$ 46,423
$ (62,424 )

Note 6—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~~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

For the Nine Months Ended September 30, 2017 For the Year Ended December 31, 2016
Balance beginning of period $ 56,108
$ 44,367
Liabilities incurred or acquired 6,644
8,945
Liabilities settled (1,408 ) (1,155 )
Revisions in estimated cash flows —
(1,695 )
Accretion expense 3,847
5,646
Balance end of period $ 65,191
$ 56,108

Note 7—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 ~~September 30, 2017~~March 31, 2020 and December 31, ~~2016~~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 Measurements at
September 30, 2017 Using
Level 1 Level 2 Level 3 Total
Financial Assets:
Commodity derivative assets $ —
$ 986
$ —
$ 986
Financial Liabilities:
Commodity derivative liabilities $ —
$ 11,284
$ —
$ 11,284


	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

Fair Value Measurements at
December 31, 2016 Using
Level 1 Level 2 Level 3 Total
Financial Assets:
Commodity derivative assets $ —
$ —
$ —
$ —
Financial Liabilities:
Commodity derivative liabilities $ —
$ 62,741
$ —
$ 62,741

The following methods and assumptions were used to estimate the fair value of the assets and liabilities in the ~~table~~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~~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~~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 ~~value~~values of the ~~2021~~2024 Senior Notes and ~~2024~~2026 Senior Notes were derived from available market data. As such, the Company has classified the ~~2021~~2024 Senior Notes and ~~2024~~2026 Senior Notes as Level 2. Please refer to Note ~~4 — Long‑Term~~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~~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

At September 30, 2017 At December 31, 2016
Carrying Amount Fair Value Carrying Amount Fair Value
2021 Senior Notes⁽¹⁾
$ 539,804
$ 580,250
$ 538,141
$ 588,500
2024 Senior Notes⁽²⁾
$ 392,766
$ 419,000
$ —
$ —


~~(1)~~	~~The carrying amount of the 2021 Senior Notes includes unamortized debt issuance costs of $10.2 million and $11.9 million as of September 30, 2017 and December 31, 2016, respectively.~~


~~(2)~~	~~The carrying amount of the 2024 Senior Notes includes unamortized debt issuance costs of $7.2 million as of September 30, 2017.~~

(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.

~~Non‑Recurring~~(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 and goodwill.~~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~~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). ~~No impairment expense was recognized for the three and nine months ended September 30, 2017 and~~For the three months ended ~~September 30, 2016 on proved oil~~March 31, 2020 and ~~gas properties. For the nine months ended September 30, 2016,~~2019, the Company recognized ~~$22.4~~$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 ~~future undiscounted cash flows~~fair value did not exceed the

~~Company’s~~ Company's carrying amount associated with its proved oil and gas properties in its northern field and it was determined that the proved oil and gas properties had no remaining fair value. Therefore, the full net book value of these proved oil and gas properties was impaired at September 30, 2016.field.

~~The Company applies the provisions of ASC 350,~~ ~~Intangibles-Goodwill and Other~~. Goodwill represents the excess of the purchase price over the estimated value of the net assets acquired in business combinations. The Company tests goodwill for impairment annually on September 30, or whenever other circumstances or events indicate that the carrying amount of goodwill may not be recoverable. The goodwill test is performed at the reporting unit level, which represents the Company’s oil and gas operations in its core DJ Basin field. If indicators of impairment are determined to exist, an impairment charge is recognized if the carrying value of goodwill exceeds its implied fair value. Any sharp prolonged decreases in the prices of oil and natural gas as well as continued declines in the quoted market price of the Company’s common shares could change the estimates of the fair value of the reporting unit and could result in an impairment charge. The Company performed an assessment as of September 30, 2017, which concluded the fair value of the reporting unit was greater than its carrying amount.

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

Note 8—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 ~~annual effective rate~~AETR applied to the year-to-date ordinary income or loss, plus the tax effect of any significant ~~discrete~~ or infrequently occurring items recorded during the interim period. The computation of the ~~annual~~ estimated ~~effective tax rate~~AETR at each interim period requires certain estimates and significant ~~judgment~~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 ~~nine~~three months ended ~~September 30, 2017~~March 31, 2020 and 2019 was ~~35.3%. During the nine months ended September 30, 2017, the Company recognized income tax benefit of $7.6 million.~~19.6% and 23.6%, respectively. The effective rate for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2020 and 2019 differs from the amount that would be provided by applying the statutory U.S. federal income tax rate of ~~35% primarily~~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 ~~taxes and estimated permanent differences. Included as a discrete item during~~attributable to non-controlling interest for the three months ended ~~September 30, 2017 is~~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 ~~deficiency related to equity compensation~~liability results in ~~excess~~tax expense of ~~compensation recognized~~$2.2 million for ~~financial reporting. The Company anticipates~~ the potential for increased periodic volatility in future effective tax rates from the impact of stock-based compensation tax deductions as they are treated as discrete tax items. The Company’s accounting predecessor was a limited liability company that was not subject to U.S. federal income tax during the first ninethree months ~~of 2016.~~ended March 31, 2020.

The Company ~~adopted ASU No. 2016-09~~considers whether some portion, or all, of the deferred tax assets (“DTAs”) will be realized based on ~~January 1, 2017. There~~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 ~~effect upon adoption as the Company did not have an accumulated windfall pool as of December 31, 2016.~~liability.

Note ~~9—Unit and Stock‑Based~~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 ~~Company reserved 20.2~~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 ~~were~~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 ~~$3.3 million and $9.9 million of~~0 stock-based compensation costs related to the stock options for the three and nine months ended September 30, 2017, respectively. These costs were included in the condensed consolidated statements of operations within the general and administrative expenses line item. The Company did not record any stock-based compensation expense related to stock options for the three ~~and nine~~ months ended ~~September 30, 2016. As of September 30, 2017, there was $26.6~~March 31, 2020, as compared to $3.8 million ~~of unrecognized compensation cost related to the stock options that is expected to be recognized over a weighted average period of 2.0 years.~~

~~The following table summarizes the stock option activity from January 1, 2017 through September 30, 2017 and provides information for stock options outstanding at the dates indicated.~~

Number of Options Weighted Average Exercise Price
Non-vested Stock Options at January 1, 2017 4,500,000
$ 19.00
Granted —
$ —
Forfeited —
$ —
Vested —
$ —
Non-vested Stock Options at September 30, 2017 4,500,000
$ 19.00

~~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 on the date of issuance. The Company assumed a forfeiture rate of zero as part of the grant date estimate of compensation cost. As of January 1, 2017, the Company elected to account for stock-based compensation forfeitures as they occur, as a result of the adoption of ASU No. 2016-09.

~~The Company recorded $8.9 million and $24.6 million of stock-based compensation costs related to RSUs~~ for the three ~~and nine~~ months ended ~~September 30, 2017, respectively. The Company did not record any stock-based compensation costs related to RSUs for the three and nine months ended September 30, 2016.~~March 31, 2019. These costs were included in the condensed consolidated statements of operations within the general and administrative expenses line item. As of ~~September 30, 2017,~~March 31, 2020, there ~~was $52.7 million of total~~are 0 remaining unrecognized compensation ~~cost~~costs related to the ~~unvested RSUs~~stock options granted to certain ~~directors, officers and employees that is expected to be recognized over a weighted average period of 1.9 years.~~executives.

~~The following table summarizes the RSU~~There was no stock option activity from January 1, ~~2017~~2020 through ~~September 30, 2017~~March 31, 2020. However, as of March 31, 2020, there was approximately 5.2 million outstanding and ~~provides information for RSUs outstanding at the dates indicated.~~exercisable stock options with a weighted-average exercise price of $18.50.

Number of Shares
Weighted Average Grant Date
Fair Value
Non-vested RSUs at January 1, 2017 3,237,500
$ 21.41
Granted 1,305,033
$ 16.43
Forfeited (403,725)
$ 19.72
Vested (85,994)
$ 16.82
Non-vested RSUs at September 30, 2017 4,052,814
$ 20.07

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 ~~will to~~ vest 25%, 25% and 25% each six months thereafter, over the remaining ~~18 month~~18-month service period. Grant date fair value was determined based on the value of ~~Extraction’s~~the Company's common stock on the date of issuance. The Company assumed a forfeiture rate of ~~zero~~0 as part of the grant date estimate of compensation cost. As of January 1, 2017, the Company elected to account for stock-based compensation forfeitures as they occur, as a result of the adoption of ASU No. 2016-09. As the vesting of any Incentive RSUs will be satisfied with shares of common stock that are already issued and outstanding, the Incentive RSUs do not have any impact on the Company’s diluted earnings per share calculation.

The Company recorded ~~$5.9 million and $12.2~~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 ~~and nine~~ months ended ~~September 30, 2017, respectively. The Company did not record any stock-based compensation costs related to Incentive RSUs for the three and nine months ended September 30, 2016.~~March 31, 2019. These costs were included in the condensed consolidated statements of operations within the general and administrative expenses line item. As of ~~September 30, 2017,~~March 31, 2020, there ~~was $26.5 million of total~~are no remaining unrecognized compensation ~~cost~~costs related to the ~~unvested~~ Incentive RSUs granted to certain ~~employees that is expected to be recognized over a weighted average period of 1.3 years.~~employees.

Note 11—Equity

Series A Preferred Stock

The ~~following table summarizes~~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 ~~Incentive RSU activity from January 1, 2017 through September 30, 2017~~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 ~~provides information for Incentive RSUs outstanding~~expect to pay future quarterly dividends in kind. The Series A Preferred Stock is convertible into shares of our common stock at the ~~dates indicated.~~

Number of Shares
Weighted Average Grant Date
Fair Value
Non-vested Incentive RSUs at January 1, 2017 2,714,368
$ 20.45
Granted —
$ —
Forfeited (703,868)
$ 20.45
Vested (507,200)
$ 20.45
Non-vested Incentive RSUs at September 30, 2017 1,503,300
$ 20.45

~~Unit-Based Compensation~~

~~The Company recorded $12.3 million and $14.9 million~~election of ~~unit-based compensation costs related~~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 ~~restricted unit awards~~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 ~~three~~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 ~~nine months ended September 30, 2016, respectively. There was no unrecognized compensation costs related~~(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 ~~these restricted unit awards as of September 30, 2017.~~the extent there are legally available funds to do so. For ~~additional disclosure regarding these restricted unit awards,~~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 ~~10—~~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 ~~(the “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 ~~and nine~~ months ended ~~September 30, 2017. EPS information is not applicable for the three~~March 31, 2020 and ~~nine months ended September 30, 2016.~~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)

For the Three Months Ended September 30, 2017 For the Nine Months Ended September 30, 2017
Basic and Diluted Loss Per Share
Net Loss $ (29,796 ) $ (13,840 )
Less: Adjustment to reflect Series A Preferred Stock dividend (2,721 ) (8,164 )
Less: Adjustment to reflect accretion of Series A Preferred Stock discount (1,365 ) (3,992 )
Adjusted net loss available to common shareholders, basic and diluted $ (33,882 ) $ (25,996 )
Denominator:
Weighted average common shares outstanding, basic and diluted⁽¹⁾
171,845
171,838
Loss Per Common Share
Basic and diluted $ (0.20 ) $ (0.15 )


~~(1)~~	For the three and nine months ended September 30, 2017, the diluted EPS calculation excludes the anti-dilutive effect of 4,500,000 common shares for stock options that were out-of-the-money, 4,052,814 RSUs and 11,472,445 common shares issuable for Series A Preferred Stock under the if-converted method.

(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 ~~11—~~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 ~~two~~for certain office ~~spaces in Denver, Colorado, one~~facilities, compressors and office ~~space in Greeley, Colorado and one office space in Houston, Texas under separate~~equipment. Maturities of operating lease ~~agreements. The Denver, Colorado leases expire on February 29,~~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 ~~May 31, 2026, respectively. The Greeley and Houston leases expire on August~~December 31, 2019, and October 31, 2017, respectively. Total rental commitments under non‑cancelable leases for office space were $19.6 million at September 30, 2017. The future minimum lease payments under these non‑cancelable leases are as follows: $0.6 million in 2017, $2.6 million in 2018, $2.5 million in 2019, $2.2 million in 2020, $2.2 million in 2021 and $9.5 million thereafter. Rent expense was $0.5$15.2 million and ~~$1.7 million for the three~~$17.4 thousand, respectively, were recorded in accounts payable and ~~nine months ended September 30, 2017, respectively, as compared to $0.6~~accrued liabilities and $14.5 million and ~~$1.3 million for~~$17.2 thousand, respectively, were recorded in other non-current liabilities on the ~~three and nine months ended September 30, 2016, respectively.~~condensed consolidated balance sheets.

On June 4, 2015, the Company subleased the remaining term of one of its Denver office leases that expires February 29, 2020. The sublease will decrease the Company’s future lease payments by $0.6 million.

Drilling Rigs

As of ~~September 30, 2017,~~March 31, 2020, the Company was subject to commitments on ~~four~~2 drilling ~~rigs.~~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 ~~$12.1~~$9.0 million as of ~~September 30, 2017,~~March 31, 2020, as required under the terms of the contracts. ~~The fourth~~Subsequent to March 31, 2020, the Company renegotiated the terms of the drilling rig ~~is expected~~contracts. After the modifications, in the event of early termination, the Company would be obligated to ~~be placed in service during the fourth quarter~~pay an aggregate amount of ~~2017 and will replace a rig currently under contract.~~approximately $8.0 million as of May 6, 2020.

Delivery Commitments

As of ~~September 30, 2017,~~March 31, 2020, the Company’s oil marketer ~~was~~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. ~~The~~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, ~~2018.~~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 ~~evaluates its contracts~~has posted a letter of credit for ~~loss contingencies and accrues for such losses, if~~this agreement in the ~~loss can be reasonably estimated and deemed probable.~~amount of $40.0 million. The Company ~~also~~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 ~~one~~2 long-term crude oil gathering ~~commitment~~commitments with ana unconsolidated ~~affiliate. It~~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 ~~for~~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 ~~$1.0 billion.~~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 ~~two~~2 new processing plants as well as the expansion of related gathering ~~systems, which are currently expected to be completed by late~~systems. The first plant commenced operations in August 2018 and ~~mid-2019, respectively, although~~ the ~~start-up date is undetermined at this time.~~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 ~~date~~dates for a period of seven years thereafter. The Company may be required to pay a shortfall fee for any ~~volumes~~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~~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. ~~Under its current drilling plans,~~

In July 2019, the Company ~~expects~~entered into 3 long-term contracts to ~~meet~~supply 125,000 dekatherms of residue gas per day for five years to a transportation company. While our production is expected to satisfy these ~~volume commitments.~~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.

~~None~~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 ~~Company’s reserves are subject~~agreement and Elevation could attempt to ~~any priorities~~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, ~~curtailments~~within 30 days of such date, Elevation could assert that ~~may affect quantities delivered~~Extraction must make a payment to ~~its customers.~~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 ~~believes~~did not complete these additional gathering facilities by April 1, 2020, and Elevation has alleged that ~~its future production~~Extraction is ~~adequate~~in breach of the Elevation Gathering Agreements. On April 2, 2020, Elevation demanded payment of $46.8 million due to ~~meet its commitments. If for some reason~~an alleged breach in contract stemming from a purported failure to complete the ~~Company’s production is not sufficient~~pipeline extensions connecting certain wells to ~~satisfy its commitments,~~the Badger central gathering facility prior to April 1, 2020. While the Company ~~expects~~disputes that these amounts are due to ~~be able~~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 ~~purchase volumes~~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 ~~market or make other arrangements to satisfy its commitments.~~

~~Acquisition~~first quarter of ~~Undeveloped Leasehold Acreage~~

~~As of September 30, 2017,~~2020 the Company ~~is party~~incurred and paid $23.5 million. The Company does not expect to ~~an agreement with an unrelated third party~~incur additional Connect Fees for ~~which it has paid $77.5 million~~the year ending December 31, 2020.

In March 2020, the Elevation Gathering Agreements were further amended to reset all gathering rates and ~~may be required to pay up to an additional $116.5 million, subject to certain customary conditions, to lease up to a total of approximately 30,000 net acres of undeveloped leasehold.~~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.

~~General~~Litigation and Legal Items

The Company is ~~subject~~involved in various legal proceedings and reviews the status of these proceedings on an ongoing basis and, from time to ~~contingent liabilities with respect to existing~~time, may settle or ~~potential claims, lawsuits~~otherwise resolve these matters on terms and ~~other proceedings, including those involving environmental, tax and other matters, certain of which~~conditions that management believes are ~~discussed more specifically below.~~in the Company’s best interests. The Company ~~accrues liabilities when it is probable that future costs will be incurred and such costs can be reasonably estimated. Such~~has provided the necessary estimated accruals are based on developments to date and the Company’s estimates of the outcomes of these matters and its experience in contesting, litigating and settling other matters. As the scope of the liabilities becomes better defined, there will be changes in the ~~estimates~~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 ~~future costs, which management currently believes~~such proceedings will not have a material adverse effect on ~~the Company’s~~our business, financial position, results of operations or ~~cash flows.~~liquidity.

~~As is customary in~~Environmental. Due to the ~~oil~~nature of the natural gas and ~~gas~~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 ~~at times have commitments~~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 ~~place to connect wells to gathering and transportation services and reserve or earn certain acreage positions or wells. If the~~these matters. 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.~~

~~Legal Matters~~

~~In the ordinary course of business, the Company may at times be subject to claims and legal actions. Management believes it is remote~~believe that ~~the impact of such matters~~any penalties that could result from these NOAVs will have a material ~~adverse~~ effect on ~~the Company’s~~our business, financial ~~position,~~condition, results of operations or ~~cash flows. Management is unaware of any pending litigation brought against~~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 ~~requiring~~was unable to connect well pads to the ~~reserve~~provider due to the inability to secure right of away 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 ~~date~~amount of ~~this filing.~~the loss cannot be reasonably estimated.

~~The Company is currently~~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 ~~discussions with~~contract stemming from a purported failure to complete the ~~Colorado Department of Public Health and Environment (“CDPHE”) regarding a Compliance Advisory issued~~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 ~~July 2015, which alleged air quality violations at three Company facilities regarding leakages~~accounts payable and accrued liabilities, related party on the condensed consolidated balance sheet as of ~~volatile organic compounds from storage tanks, all~~March 31, 2020 and in other operating expenses on the condensed consolidated statements of which were promptly addressed. The Company continues to work with the CDPHE on its investigation into the Company's facilities and it intends to seek a field-wide administrative settlement of these issues. At this time, we anticipate the remediation and compliance costs that this matter may impose upon us to be an immaterial amount.operations.

Note ~~12—~~14—Related Party Transactions

~~Office Lease with Related Affiliate~~

In April 2016, the Company subleased office space to Star Peak Capital, LLC, of which a member of the board of directors is an owner, for $1,400 per month. The sublease commenced on May 1, 2016 and expires on February 28, 2020.

~~2021~~2024 Senior Notes

Several ~~lenders of the 2021 Senior Notes are also~~ 5% stockholders of the ~~Company. As of the initial issuance in July 2016 of the $550.0 million principal amount on the 2021 Senior Notes, such stockholders held $63.5 million.~~

~~2024 Senior Notes~~

~~Several lenders~~Company were also holders of the 2024 Senior ~~Notes are also 5% stockholders of the Company.~~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.

~~Series A Preferred Stock~~2026 Senior Notes

Several holders of the ~~Series A Preferred Stock~~2026 Senior Notes are also 5% stockholders of the Company. As of the initial issuance in ~~October 2016~~January 2018 of the ~~$185.3~~$750.0 million ~~of Series A Preferred Stock,~~principal amount on the 2026 Senior Notes, such stockholders held ~~$105.0~~$56.2 million.

~~Long-Term Crude Oil Gathering Commitment~~Elevation Midstream, LLC

~~The~~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 ~~has a long-term~~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 ~~commitment with an unconsolidated affiliate. It has~~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 ~~term~~single operating segment.

The following table presents a reconciliation of ~~ten years~~Adjusted EBITDAX by segment to the GAAP financial measure of income (loss) before income taxes for ~~an average~~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)

Table of ~~9,167 Bbl/d in year one, 17,967 Bbl/d in year two, 18,800 Bbl/d in years~~Contents

Financial information of the Company's reportable segments was as follows for the three ~~through five~~months ended March 31, 2020 and ~~10,000 Bbl/d in years six through ten. The aggregate amount~~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

Table of ~~estimate payments under this agreement is $71.9 million.~~Contents

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;~~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;

~~hazardous, risky~~

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•drilling operations ~~including those~~ 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;

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

•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.~~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, ~~2016~~2019 (our “Annual Report”) and in our other filings with the Securities and Exchange Commission, which could materially affect our ~~businesses,~~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. ~~There has~~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 ~~its~~our Annual Report and analyzes the changes in the results of operations between the three ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2020 and ~~2016.~~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 ~~DJ Basin.~~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~~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 ~~growing~~improving cash flow and our ~~proved reserves and production primarily through the development of our large inventory of identified liquids‑rich horizontal drilling locations.~~liquidity while reducing debt.

Financial Results

For the three ~~and nine~~ months ended ~~September 30, 2017,~~March 31, 2020, crude oil, natural gas and NGL sales, coupled with the impact of settled derivatives, increased to ~~$183.7~~$204.5 million ~~and $384.3 million, respectively,~~ as compared to ~~$77.6~~$202.0 million ~~and $215.9 million, respectively,~~ in the same prior year ~~periods~~period due to an increase in sales volumes of ~~3,122~~approximately 1,341 MBoe, and 5,380 MBoe, respectively. The increase in crude oil, natural gas and NGL sales for the three and nine months ended September 30, 2017 as compared to the same prior year period was also due to an increasepartially offset by a decrease of ~~$2.64 and $0.94, respectively,~~$4.25 in realized price per BOE, including settled derivatives.

For the three ~~and nine~~ months ended ~~September 30, 2017,~~March 31, 2020, we had net ~~loss~~income of ~~$29.8~~$9.0 million ~~and $13.8 million, respectively,~~ as compared to a net loss of ~~$37.3 million and $210.4~~$94.0 million for the three ~~and nine~~ months ended ~~September 30, 2016, respectively.~~March 31, 2019. The ~~changes~~change to net income for the three months ended March 31, 2020 from net loss ~~were~~for the three months ended March 31, 2019 was primarily driven by an increase in ~~sales revenues~~commodity derivative gain of ~~$108.0~~$385.1 million, and $206.9 million, respectively and a decrease in interest expense of $16.1 million and $24.2 million, respectively. Additionally, net loss decreased due to an increase in the income tax benefit of $17.1 million and $7.6 million for the three and nine months ended September 30, 2017 as compared to September 30, 2016, respectively. These increases werepartially offset by an increase in operating expenses of ~~$80.5~~$112.0 million and ~~$152.5~~a decrease in sales revenue of $56.7 million.

Adjusted EBITDAX was $123.9 million ~~respectively, primarily related to increased sales volumes. The increase to net loss~~ for the three months ended ~~September 30, 2017 and 2016 was also driven by an decrease from a gain~~March 31, 2020 as compared to a loss on commodity derivatives of $54.1 million. The decrease to net loss for the nine months ended September 30, 2017 and 2016 was also driven by an increase from a loss to a gain on commodity derivatives of $108.8 million.

~~Adjusted EBITDAX was $128.4 million and $245.8~~$138.2 million for the three ~~and nine~~ months ended ~~September 30, 2017, respectively, as compared to $48.2 million and $138.0 million for the three and nine months ended September 30, 2016, respectively,~~March 31, 2019, reflecting a ~~166.6% and 78.1% increase, respectively.~~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 September 30, 2017, our aggregate drilling, completion, leasehold and midstream capital expenditures, excluding acquisitions and business combinations, totaled $302.7 million, $252.4 million of which was drilling and completion. We invested $47.2 million on leasehold and $3.1 million for midstream. Our total drilling and completion capital expenditures for the nine months ended September 30, 2017 were approximately $701.1 million, including $30.7 million for non-operated drilling and completion.

During the three months ended ~~September 30, 2017,~~March 31, 2020, we ~~reached total depth~~focused on 53improving free cash flow and implemented operational efficiencies to reduce drilling and completion costs. We incurred approximately $146.6 million in drilling 34 gross ~~(35~~(24.5 net) wells with an average lateral length of ~~approximately 8,300 feet~~2.3 miles and ~~completed 51~~completing 28 gross ~~(34~~(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 ~~10,300 feet. We turned to sales 30 gross (27 net) wells with an average lateral length~~$8.8 million of ~~approximately 7,900 feet. We completed 3,053 total fracturing stages during the quarter while pumping approximately 965 million pounds of proppant.~~leasehold and surface acreage additions.

Recent Developments

~~October 2017 Credit Facility Amendment~~COVID-19 Outbreak and Global Industry Downturn

~~On October 11, 2017, we amended~~The recent worldwide outbreak in several countries, including the ~~revolving credit facility~~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 ~~things, (i) provide for the joinder of new lenders, (ii) increase the borrowing base under the credit facility~~countries such as Russia further increased uncertainty and volatility around global oil supply-demand dynamics. Decreased demand from ~~$375.0 million to $525.0 million, and (iii) amend certain provisions~~much of the ~~credit agreement, including~~United States being on lockdown to prevent the ~~commitments~~spread of COVID-19 caused domestic storage capacity to begin to fill up during March and ~~allocations~~April causing further price declines and ultimately causing oil prices to plummet. We expect the excess supply of ~~each lender.~~oil and natural gas in the United States to continue for a sustained period.

~~August 2017 Credit Facility Amendment~~The COVID-19 outbreak and ~~Restatement~~

~~On August 16, 2017,~~its development into a pandemic in March 2020 have required that we ~~entered into an amendment~~take precautionary measures intended to help minimize the risk to our business, employees, customers, suppliers and ~~restatement~~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 existing credit facility, which provides commitments of $1.5 billion with a syndicate of banks, which is subject to a borrowing base of $375.0 million. The credit facility matures on the earlier of (a) August 16, 2022, (b) January 15, 2021 if (and only if) the Company's 2021 Senior Notes (as defined below)non-operational employees are now working remotely. We have not ~~been refinanced~~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 ~~repaid~~shut-in a substantial portion of our current production volumes and will continue to evaluate such a measure on a regular basis in ~~full on or prior~~response to ~~January 15, 2021, (c) April 15, 2021, if (and only if) (i) the convertible preferred equity interests issued~~market conditions and contractual obligations. As substantially all of our revenues are generated by the ~~Company has not been converted into common equity~~production and sale of hydrocarbons, the curtailment or ~~redeemed prior~~shut-in of our production could adversely affect our business, financial condition, results of operations, liquidity, and ability to ~~April 15, 2021,~~finance planned capital expenditures.

Please also see Part II, Item 1A in our Annual Report and ~~(ii) prior~~in this Quarterly Report for further information related to ~~April 15, 2021,~~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 ~~maturity date~~deconsolidation of Elevation Midstream, LLC.

Reduction in Workforce

We recorded involuntary termination charges of $5.8 million in the ~~Series A Preferred Stock has not been extended~~first quarter of 2020 primarily related to ~~a date that is no earlier than six months after August 16, 2022 or (d)~~one-time involuntary termination benefits, office closure and relocation benefits communicated to our workforce in February 2020. This plan was initiated to align the ~~earlier termination in whole~~size and composition of our workforce with our expected future operating and capital plans.

February 2020 Divestiture

In February 2020, we completed the ~~commitments.~~

~~2024 Senior Notes~~

~~On August 1, 2017, we issued at par $400.0 million principal amount~~sale 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 commencing on November 15, 2017. We received netcertain non-operated producing properties for aggregate sales proceeds of approximately ~~$392.6~~$12.2 million, ~~after deducting discounts~~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 ~~fees. We intend~~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 ~~net proceeds~~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 ~~2024 Senior Notes Offering~~threshold to ~~partially fund~~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 ~~2017 capital expenditures~~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 ~~general corporate purposes.~~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; ~~and~~

•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 ~~NGL~~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 ~~September 30, 2017,~~March 31, 2020, our revenues were derived ~~73%~~75% from oil sales, 14% ~~from natural gas sales and 13% from NGL sales. For the three months ended September 30, 2016, our revenues were derived 71% from oil sales, 18%~~ from natural gas sales and 11% from NGL sales. For the ~~nine~~three months ended ~~September 30, 2017,~~March 31, 2019, our revenues were derived ~~69%~~75% from oil sales, 16% from natural gas sales and ~~15% from NGL sales. For the nine months ended September 30, 2016, our revenues were derived 74% from oil sales, 15% from natural gas sales and 11%~~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 ~~our properties 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

For the Three Months Ended
September 30,

For the Nine Months Ended
September 30,
2017 2016 2017 2016
Oil (MBbl) 3,184
1,290
6,496
3,808
Natural gas (MMcf) 8,953
4,792
21,713
12,851
NGL (MBbl) 1,109
574
2,695
1,479
Total (MBoe) 5,785
2,663
12,809
7,429
Average net sales (BOE/d) 62,884
28,948
46,921
27,114

As reservoir ~~pressure declines,~~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. ~~Accordingly, we plan to maintain our focus on adding reserves through organic growth as well as acquisitions.~~ 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 ~~September 30, 2017,~~March 31, 2020, NYMEX West Texas Intermediate oil prices ranged from a high of $107.26 per Bbl to a low of ~~$26.21~~$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 ~~$1.64~~$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 ~~continuing into 2017~~2020 are due to a combination of factors including increased U.S. supply, global economic concerns stemming from COVID-19 and ~~geopolitical risks.~~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 ~~predominately~~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

For the Three Months Ended
September 30,

For the Nine Months Ended
September 30,
2017 2016 2017 2016
Oil
NYMEX WTI High ($/Bbl) $ 52.22
$ 48.99
$ 54.45
$ 51.23
NYMEX WTI Low ($/Bbl) $ 44.23
$ 39.51
$ 42.53
$ 26.21
NYMEX WTI Average ($/Bbl) $ 48.20
$ 44.94
$ 49.36
$ 41.53
Average Realized Price ($/Bbl) $ 41.48
$ 40.11
$ 41.50
$ 35.68
Average Realized Price, with derivative settlements ($/Bbl) $ 42.14
$ 42.73
$ 40.61
$ 41.93
Average Realized Price as a % of Average NYMEX WTI 86.1 % 89.3 % 84.1 % 85.9 %
Differential ($/Bbl) to Average NYMEX WTI $ (6.72 ) $ (4.83 ) $ (7.86 ) $ (5.85 )
Natural Gas
NYMEX Henry Hub High ($/MMBtu) $ 3.15
$ 3.06
$ 3.42
$ 3.06
NYMEX Henry Hub Low ($/MMBtu) $ 2.77
$ 2.55
$ 2.56
$ 1.64
NYMEX Henry Hub Average ($/MMBtu) $ 2.95
$ 2.79
$ 3.05
$ 2.35
Average Realized Price ($/Mcf) $ 2.76
$ 2.67
$ 2.91
$ 2.16
Average Realized Price, with derivative settlements ($/Mcf) $ 2.84
$ 2.94
$ 2.90
$ 2.84
Average Realized Price as a % of Average NYMEX Henry Hub⁽¹⁾
84.9 % 87.0 % 86.6 % 83.4 %
Differential ($/Mcf) to Average NYMEX Henry Hub⁽¹⁾
$ (0.49 ) $ (0.40 ) $ (0.45 ) $ (0.43 )
NGL
Average Realized Price ($/Bbl) $ 21.74
$ 14.54
$ 21.36
$ 13.37
Average Realized Price as a % of Average NYMEX WTI 45.1 % 32.4 % 43.3 % 32.2 %
(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.


~~(1)~~	~~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.

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. ~~The following summarizes~~

For a description of our derivative ~~positions related to crude oil~~instruments that we utilize and ~~natural gas sales in effect~~a summary of our commodity derivative contracts as of ~~September 30, 2017:~~March 31, 2020, please see Note 6—Commodity Derivative Instruments in Part I, Item 1. Financial Information of this Quarterly Report.

2017 2018 2019
NYMEX WTI⁽¹⁾ Crude Swaps:

Notional volume (Bbl) 1,850,000
5,100,000
—
Weighted average fixed price ($/Bbl) $ 50.64
$ 51.61

NYMEX WTI⁽¹⁾ Crude Sold Calls:

Notional volume (Bbl) 1,200,000
6,190,000
3,000,000
Weighted average sold call price ($/Bbl) $ 53.04
$ 55.75
$ 55.10
NYMEX WTI⁽¹⁾ Crude Sold Puts:

Notional volume (Bbl) 3,225,000
11,338,800
3,000,000
Weighted average sold put price ($/Bbl) $ 37.19
$ 38.93
$ 39.70
NYMEX WTI⁽¹⁾ Crude Purchased Puts:

Notional volume (Bbl) 1,800,000
6,838,800
3,000,000
Weighted average purchased put price ($/Bbl) $ 42.13
$ 47.35
$ 49.37
NYMEX HH⁽²⁾ Natural Gas Swaps:

Notional volume (MMBtu) 7,420,000
37,200,000
—
Weighted average fixed price ($/MMBtu) $ 3.06
$ 3.10

NYMEX HH⁽²⁾ Natural Gas Purchased Puts:

Notional volume (MMBtu) —
2,400,000
—
Weighted average purchased put price ($/MMBtu) $ 3.00

NYMEX HH⁽²⁾ Natural Gas Sold Calls:

Notional volume (MMBtu) —
2,400,000
—
Weighted average sold call price ($/MMBtu) $ 3.15

CIG⁽³⁾ Basis Gas Swaps:

Notional volume (MMBtu) 5,215,000
6,300,000
—
Weighted average fixed basis price ($/MMBtu) $ (0.31 ) $ (0.31 )


~~(1)~~	~~NYMEX WTI refers to West Texas Intermediate crude oil price on the New York Mercantile Exchange~~


~~(2)~~	~~NYMEX HH refers to the Henry Hub natural gas price on the New York Mercantile Exchange~~


~~(3)~~	~~CIG refers to the NYMEX HH settlement price less the fixed basis price, the Rocky Mountains (CIGC) settlement price.~~

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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For the Nine Months Ended
September 30,
2017 2016
NYMEX HH⁽¹⁾ Natural Gas Swaps:

Notional volume (MMBtu) 18,000,000
9,879,600
Weighted average fixed price ($/MMBtu) $ 3.05
$ 3.15
CIG⁽³⁾ Basis Gas Swaps:

Notional volume (MMBtu) 7,400,000
1,980,000
Weighted average fixed basis price ($/MMBtu) $ (0.35 ) (0.19 )
NYMEX WTI⁽²⁾ Crude Swaps:

Notional volume (Bbl) 2,275,000
1,464,060
Weighted average fixed price ($/Bbl) $ 45.88
$ 43.01
NYMEX WTI⁽²⁾ Crude Sold Puts:

Notional volume (Bbl) 4,495,000
1,350,000
Weighted average strike price ($/Bbl) $ 38.02
$ 44.89
NYMEX WTI⁽²⁾ Crude Purchased Puts:

Notional volume (Bbl) 3,770,000
3,599,150
Weighted average strike price ($/Bbl) $ 46.63
$ 51.94
NYMEX WTI⁽²⁾ Crude Sold Calls:

Notional volume (Bbl) 3,420,000
1,947,090
Weighted average strike price ($/Bbl) $ 55.28
$ 61.29
NYMEX WTI⁽²⁾ Crude Purchased Calls:

Notional volume (Bbl) 300,000
216,000
Weighted average strike price ($/Bbl) $ 60.83
$ 69.58
Total Amounts Received/(Paid) from Settlement (in thousands) $ (6,022 ) $ 37,947
Cash provided by (used in) changes in Accounts Receivable and Accounts Payable related to Commodity Derivatives $ (2,871 ) $ 5,068
Cash Settlements on Commodity Derivatives per Consolidated Statements of Cash Flows $ (8,893 ) $ 43,015


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)


~~(1)~~	~~NYMEX HH refers to the Henry Hub natural gas price on the New York Mercantile Exchange~~


~~(2)~~	~~NYMEX WTI refers to West Texas Intermediate crude oil price on the New York Mercantile Exchange~~


~~(3)~~	~~CIG refers to the NYMEX HH settlement price less the fixed basis price, the Rocky Mountains (CIGC) settlement price~~

Lease Operating Expenses

All direct and allocated indirect costs of lifting hydrocarbons from a producing formation to the surface ~~constitute~~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 ~~and~~or completion expenses. ~~LOE also includes expenses incurred to gather and deliver natural gas to the processing plant and/or selling point.~~

Capital Expenditures

For the ~~nine~~three months ended ~~September 30, 2017,~~March 31, 2020, we incurred approximately ~~$701.1~~$146.6 million in drilling and completion capital ~~expenditures in connection with~~expenditures. For the ~~drilling of 141~~three months ended March 31, 2020, we drilled 34 gross ~~(98~~(24.5 net) wells with an average lateral length of approximately ~~8,700 feet~~2.3 miles and completed ~~156~~28 gross ~~(133~~(22.7 net) wells with an average lateral length of approximately ~~8,200 feet.~~2.3 miles. We turned to sales ~~123~~13 gross ~~(116~~(12 net) wells with an average lateral length of approximately ~~7,300 feet.~~2.1 miles. In addition, we incurred approximately ~~$98.6~~$8.8 million of leasehold and surface acreage ~~additions and approximately $7.8 million of midstream and infrastructure additions, excluding amounts paid for asset acquisitions and business combinations.~~additions.

Our initial 2017 capital budget was approximately $795 million to $935 million, substantially all of which we intend to allocate to the DJ Basin. We intend to allocate approximately $675 million to $775 million of our 2017 capital budget to the drilling of 185 to 190 gross operated wells and the completion of 190 to 195 gross operated wells, approximately $60 to $80 million of non-operated drilling and completion, and approximately $60 million to $80 million to undeveloped leasehold acquisitions, midstream, and other capital expenditures. We are currently running a three rig program and plan to remain with a three rig program throughout 2017. Our capital budget excludes any amounts that were or may be paid for potential acquisitions.

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 ~~generally accepted accounting principles ("GAAP").~~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")~~(DD&A), impairment of long lived assets, non-recurring charges in other operating expenses, exploration and abandonment expenses, ~~rig termination fees, acquisition transaction expenses, commodity derivative~~gain on sale of property and equipment, (gain) loss on commodity derivatives, settlements on commodity ~~derivatives,~~derivative instruments, premiums paid for derivatives that settled during the period, ~~unit and~~ stock-based compensation expense, amortization of debt ~~discount and debt~~ issuance costs, gain on repurchase of senior notes, interest expense, income ~~taxes~~tax expense (benefit) and ~~non-recurring charges.~~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:~~

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 ~~loss~~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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For the Three Months Ended
September 30,

For the Nine Months Ended
September 30,
2017 2016 2017 2016
Reconciliation of Net Loss to Adjusted EBITDAX:
Net loss $ (29,796 ) $ (37,267 ) $ (13,840 ) $ (210,400 )
Add back:
Depletion, depreciation, amortization and accretion 94,220
46,680
213,483
141,317
Impairment of long lived assets —
467
675
23,350
Exploration expenses 7,181
5,985
24,431
14,735
Rig termination fee —
—
—
891
Loss on sale of property and equipment —
—
451
—
Acquisition transaction expenses —
345
68
345
(Gain) loss on commodity derivatives 37,875
(16,225 ) (46,423 ) 62,424
Settlements on commodity derivative instruments 3,162
4,787
(6,022 ) 37,947
Premiums paid for derivatives that settled during the period (293 ) (132 ) 20
(5,470 )
Unit and stock-based compensation expense 18,110
12,315
46,707
14,922
Amortization of debt discount and debt issuance costs 1,469
15,905
3,181
18,330
Interest expense 13,611
15,311
30,580
39,584
Income tax benefit (17,106 ) —
(7,556 ) —
Adjusted EBITDAX $ 128,433
$ 48,171
$ 245,755
$ 137,975
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.

~~On October 3, 2016, we acquired additional oil~~•Elevation Midstream, LLC was deconsolidated as of March 16, 2020 and ~~gas properties primarily located~~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 ~~Wattenberg Field located primarily around our existing Greeley~~condensed consolidated statements of operations for the three months ended March 31, 2020. Please see Note 1—Business and ~~Windsor areas. The October 2016 Acquisition consisted~~Organization in Part I, Item 1. Financial Information of ~~working interest~~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 ~~approximately 6,400 net acres and 31 gross (19 net) drilled but uncompleted~~contract stemming from a purported failure to complete the pipeline extensions connecting certain wells ~~as of~~to the ~~date of acquisition. The October 2016 Acquisition provided net daily production of approximately 6,900 BOE/d during~~Badger central gathering facility prior to April 1, 2020. While the ~~fourth quarter 2016.~~

~~As a result of the initial public offering (“IPO”)~~Company disputes that these amounts are due to Elevation, under ASC Topic 450 - Contingencies, we ~~expect to incur additional general and administrative~~recorded the amount in other operating expenses ~~related to being a public company, including Exchange Act reporting expenses; expenses associated with Sarbanes-Oxley Act compliance; expenses associated with listing~~ on the NASDAQ Global Select Market; incremental independent auditor fees; incremental legal fees; investor relations expenses; registrar and transfer agent fees; incremental director and officer liability insurance costs; and directors compensation.

~~In October 2016, our board~~condensed consolidated statements of ~~directors adopted~~operations for the Extraction Oil & Gas, Inc. 2016 Long Term Incentive Plan ("LTIP") and granted awards to certain directors and officers, including stock options and restricted stock units. We recognized $18.1 million and $46.7 million of stock-based compensation expense for three ~~and nine~~ months ended ~~September 30, 2017 related to these awards.~~March 31, 2020.

Prior to the Corporate Reorganization, we were not subject to federal or state income taxes. Accordingly, the financial data attributable to us prior to such corporate reorganization contain no provision for federal or state income taxes because the tax liability with respect to Holdings’ taxable income was passed through to its members. Beginning October 12, 2016, we began to be taxed as a C corporation under the Internal Revenue Code and subject to federal and state income taxes at a blended statutory rate

Table of ~~approximately 38% of pretax earnings.~~Contents

Historical Results of Operations and Operating Expenses

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

~~The following table provides the~~For components of our revenues, operating expenses, other income (expense) and net ~~loss for the periods indicated (in thousands):~~income (loss), please see our condensed consolidated statements of operations in Part I, Item 1. Financial Information of this Quarterly Report.

For the Three Months Ended
September 30,

For the Nine Months Ended
September 30,
2017 2016 2017 2016
(Unaudited)
Revenues:
Oil sales $ 132,075
$ 51,760
$ 269,597
$ 135,896
Natural gas sales 24,672
12,792
63,095
27,730
NGL sales 24,114
8,350
57,574
19,773
Total Revenues 180,861
72,902
390,266
183,399
Operating Expenses:
Lease operating expenses 29,267
15,480
75,755
40,819
Production taxes 16,290
6,186
33,254
16,935
Exploration expenses 7,181
5,985
24,431
14,735
Depletion, depreciation, amortization and accretion 94,220
46,680
213,483
141,317
Impairment of long lived assets —
467
675
23,350
Other operating expenses —
—
451
891
Acquisition transaction expenses —
345
68
345
General and administrative expenses 28,741
20,071
77,916
35,189
Total Operating Expenses 175,699
95,214
426,033
273,581
Operating Income (Loss) 5,162
(22,312 ) (35,767 ) (90,182 )
Other Income (Expense):
Commodity derivatives gain (loss) (37,875 ) 16,225
46,423
(62,424 )
Interest expense (15,080 ) (31,216 ) (33,761 ) (57,914 )
Other income 891
36
1,709
120
Total Other Income (Expense) (52,064 ) (14,955 ) 14,371
(120,218 )
Loss Before Income Taxes (46,902 )
(37,267 )
(21,396 )
(210,400 )
Income tax benefit (17,106 ) —
(7,556 ) —
Net Loss $ (29,796 ) $ (37,267 ) $ (13,840 ) $ (210,400 )

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		%

For the Three Months Ended For the Nine Months Ended
September 30, September 30,
2017 2016 2017 2016
Sales (MBoe)⁽¹⁾:
5,785
2,663
12,809
7,429
Oil sales (MBbl) 3,184
1,290
6,496
3,808
Natural gas sales (MMcf) 8,953
4,792
21,713
12,851
NGL sales (MBbl) 1,109
574
2,695
1,479
Sales (BOE/d)⁽¹⁾:
62,884
28,948
46,921
27,114
Oil sales (Bbl/d) 34,607
14,025
23,794
13,899
Natural gas sales (Mcf/d) 97,311
52,083
79,536
46,902
NGL sales (Bbl/d) 12,059
6,242
9,871
5,397
Average sales prices⁽²⁾:

Oil sales (per Bbl) $ 41.48
$ 40.11
$ 41.50
$ 35.68
Oil sales with derivative settlements (per Bbl) 42.14
42.73
40.61
41.93
Natural gas sales (per Mcf) 2.76
2.67
2.91
2.16
Natural gas sales with derivative settlements (per Mcf) 2.84
2.94
2.90
2.84
NGL sales (per Bbl) 21.74
14.54
21.36
13.37
Average price (per BOE) 31.26
27.38
30.47
24.69
Average price with derivative settlements (per BOE) 31.76
29.12
30.00
29.06
Expense per BOE:
Lease operating expenses $ 5.06
$ 5.81
$ 5.91
$ 5.49
Operating expenses 2.67
3.57
3.25
3.46
Transportation and gathering 2.39
2.24
2.66
2.03
Production taxes 2.82
2.32
2.60
2.28
Exploration expenses 1.24
2.25
1.91
1.98
Depletion, depreciation, amortization and accretion 16.29
17.53
16.67
19.02
Impairment of long lived assets —
0.18
0.05
3.14
Other operating expenses —
—
0.04
0.12
Acquisition transaction expenses —
0.13
0.01
0.05
General and administrative expenses 4.97
7.54
6.08
4.74
Cash general and administrative expenses 1.84
2.92
2.43
2.73
Unit and stock-based compensation 3.13
4.62
3.65
2.01
Total operating expenses per BOE $ 30.38
$ 35.76
$ 33.27
$ 36.82


~~(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 our 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.

(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 ~~September 30, 2017~~March 31, 2020 Compared to Three Months Ended ~~September 30, 2016~~March 31, 2019

Oil sales revenues. Crude oil sales revenues ~~increased~~decreased by ~~$80.3~~$41.2 million to ~~$132.1~~$124.2 million for the three months ended ~~September 30, 2017~~March 31, 2020 as compared to crude oil sales of ~~$51.8~~$165.4 million for the three months ended ~~September 30, 2016. An~~ ~~increase~~March 31, 2019. A decrease in sales volumes between these periods contributed a ~~$76.0~~$3.7 million ~~positive~~negative impact, ~~while an~~ ~~increase~~and a decrease in crude oil prices contributed a ~~$4.3~~$37.5 million ~~positive~~negative impact.

For the three months ended ~~September 30, 2017,~~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 ~~34.6~~38.5 MBbl/d. Our crude oil sales volume ~~increased~~ ~~147%~~decreased by 0.1 to ~~3,184~~3.5 MBbl for the three months ended ~~September 30, 2017~~March 31, 2020 compared to ~~1,290~~3.6 MBbl for the three months ended ~~September 30, 2016.~~March 31, 2019. The volume ~~increase~~decrease is primarily due to the natural decline of our existing properties, partially offset by an increase in production from the completion of ~~172~~28 gross wells from ~~October~~January 1, ~~2016~~2020 to ~~September 30, 2017, partially offset by the natural decline of our existing properties.~~March 31, 2020.

The average price we realized on the sale of crude oil was ~~$41.48~~$35.45 per Bbl for the three months ended ~~September 30, 2017~~March 31, 2020 compared to ~~$40.11~~$46.17 per Bbl for the three months ended ~~September 30, 2016.~~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 ~~increased~~decreased by ~~$11.9~~$13.6 million to ~~$24.7~~$22.3 million for the three months ended ~~September 30, 2017~~March 31, 2020 as compared to natural gas sales revenues of ~~$12.8~~$35.9 million for the three months ended ~~September 30, 2016.~~March 31, 2019. An increase in sales volumes between these periods contributed a ~~$11.1~~$13.0 million positive impact, while an ~~increase~~a decrease in natural gas prices contributed a ~~$0.8~~$26.6 million ~~positive~~ ~~impact due to increasing natural gas prices.~~negative impact.

For the three months ended ~~September 30, 2017,~~March 31, 2020, our natural gas sales averaged ~~97.3~~208.8 MMcf/d. Natural gas sales volumes increased by ~~87%~~5.0 to ~~8,953~~19.0 MMcf for the three months ended ~~September 30, 2017~~March 31, 2020 as compared to ~~4,792~~14.0 MMcf for the three months ended ~~September 30, 2016.~~March 31, 2019. The volume increase is primarily due to the completion of ~~172~~28 gross wells from ~~October~~January 1, ~~2016~~2020 to ~~September 30, 2017,~~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 ~~$2.76~~$1.17 per Mcf for the three months ended ~~September 30, 2017~~March 31, 2020 compared to ~~$2.67~~$2.57 per Mcf for the three months ended ~~September 30, 2016.~~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 ~~increased~~decreased by ~~$15.7~~$3.4 million to ~~$24.1~~$17.2 million for the three months ended ~~September 30, 2017~~March 31, 2020 as compared to NGL sales revenues of ~~$8.4~~$20.6 million for the three months ended ~~September 30, 2016.~~March 31, 2019. An increase in sales volumes between these periods contributed a ~~$7.7~~$8.9 million positive impact, while an ~~increase~~a decrease in price contributed a ~~$8.0~~$12.3 million ~~positive~~negative impact.

For the three months ended ~~September 30, 2017,~~March 31, 2020, our NGL sales averaged ~~12.1~~20.9 MBbl/d. NGL sales volumes increased by ~~93%~~0.6 to ~~1,109~~1.9 MBbl for the three months ended ~~September 30, 2017~~March 31, 2020 as compared to ~~574~~1.3 MBbl for the three months ended ~~September 30, 2016.~~March 31, 2019. The volume increase is primarily due to the completion of ~~172~~28 gross wells ~~from October 1, 2016 to September 30, 2017,~~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 ~~$21.74~~$9.02 per Bbl for the three months ended ~~September 30, 2017~~March 31, 2020 compared to ~~$14.54~~$15.53 per Bbl for the three months ended ~~September 30, 2016.~~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 ~~$13.8~~$8.5 million to ~~$29.3~~$30.4 million for the three months ended ~~September 30, 2017,~~March 31, 2020, from ~~$15.5~~$21.9 million for the three months ended September 30, 2016. The increase in LOE was comprised of an increase in transportation and gathering (“T&G”) expense of $7.8 million for the three months ended September 30, 2017 compared to the three months ended September 30, 2016 and an increase in operating expenses of $6.0 million for the three months ended September 30, 2017 compared to the three months ended September 30, 2016.March 31, 2019. The increase in LOE was primarily the result of an increase in producing wells and an increase in ~~both residue natural gas and NGL sales volumes and realized prices, resulting in collectively higher T&G fees.~~

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 ~~decreased~~ ~~from $5.81~~increased to $3.54 per BOE sold for the three months ended ~~September 30, 2016~~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 ~~$5.06~~$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 ~~September 30, 2017. The decrease in LOE~~March 31, 2020 compared to $1.43 per BOE ~~is primarily a result of flush production on several new pads turned-in-line during~~sold for the three months ended ~~September 30, 2017.~~March 31, 2019.

Production taxes. Our production taxes ~~increased~~decreased by ~~$10.1~~$4.6 million to ~~$16.3~~$13.5 million for the three months ended ~~September 30, 2017~~March 31, 2020 as compared to ~~$6.2~~$18.1 million for the three months ended ~~September 30, 2016.~~March 31, 2019. The ~~increase~~decrease is primarily attributable to ~~increased~~decreased revenue as production taxes are calculated as a percentage of sales revenue. Production taxes as a

percentage of sales revenue was ~~9.0%~~8.1% for the three months ended ~~September 30, 2017~~March 31, 2020 as compared to ~~8.5%~~8.2% for the three months ended ~~September 30, 2016.~~March 31, 2019. The ~~increase~~consistency in production taxes as a percentage of sales revenue relates to ~~a change in the~~comparatively constant estimated ad valorem and severance tax ~~rate~~rates for the three months ended ~~September 30, 2017.~~March 31, 2020.

Exploration and abandonment expenses. Our exploration and abandonment expenses were ~~$7.2~~$112.5 million for the three months ended ~~September 30, 2017. We recognized $4.6~~March 31, 2020, of which $106.9 million ~~in expense attributable~~was lease abandonment expense. Due to the ~~extension~~decrease in pricing, all of ~~certain leases, $1.4 million attributable to exploratory geological~~the unproved property in our northern field was abandoned and ~~geophysical costs and $1.2 million in impairment expense attributable to the abandonment and impairment of unproved properties for the three months ended September 30, 2017.~~impaired. For the three months ended ~~September 30, 2016,~~March 31, 2019, we recognized ~~$6.0~~$6.2 million in exploration and abandonment expenses.

Depletion, depreciation, amortization and accretion expense. Our DD&A expense ~~increased~~ ~~$47.5~~decreased $42.7 million to ~~$94.2~~$76.1 million for the three months ended ~~September 30, 2017~~March 31, 2020 as compared to ~~$46.7~~$118.8 million for the three months ended ~~September 30, 2016. This increase is due to an increase in volumes sold for the three months ended September 30, 2017 as sales~~ ~~increased~~ ~~by approximately 3,122 MBoe.~~March 31, 2019. On a per unit basis, DD&A expense decreased ~~from $17.53~~ to $8.87 per BOE for the three months ended ~~September 30, 2016 to $16.29~~March 31, 2020 from $16.41 per BOE for the three months ended ~~September 30, 2017.~~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.~~expenses ("G&A"). General and administrative ~~(“G&A”)~~ expenses ~~increased~~decreased by ~~$8.6~~$17.1 million to ~~$28.7~~$10.6 million for the three months ended ~~September 30, 2017~~March 31, 2020 as compared to ~~$20.1~~$27.7 million for the three months ended ~~September 30, 2016.~~March 31, 2019. This ~~increase~~decrease is primarily due to ~~an increase~~a one-time reduction of workforce during the first quarter of 2020, and a decrease in ~~our employee head count and unit and~~ stock-based compensation expense recognized for the three months ended ~~September 30, 2017~~March 31, 2020 compared to the three months ended ~~September 30, 2016.~~March 31, 2019. On a per unit basis, G&A expense decreased ~~from $7.54~~to $1.24 per BOE sold for the three months ended ~~September 30, 2016 to $4.97~~March 31, 2020 from $3.82 per BOE sold for the three months ended ~~September 30, 2017.~~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~~non-cash expense for ~~unit and stock‑based~~stock-based compensation for equity awards granted to our employees and directors. For the three months ended ~~September 30, 2017, stock‑based~~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 ~~$18.1 million as compared to unit-based compensation of $12.3~~$13.0 million.

Other operating expenses. Other operating expenses were $52.6 million for the three months ended ~~September 30, 2016. The increase~~March 31, 2020. This amount is ~~due~~primarily made up of a $46.8 million loss contingency from an alleged breach in contract stemming from a purported failure to ~~additional equity awards granted~~complete the pipeline extensions connecting certain wells to ~~employees as part~~the Badger central gathering

Table of ~~our 2016 Long Term Incentive Plan that was adopted~~Contents

facility prior to April 1, 2020. Also included in ~~October 2016~~this amount is a $5.8 million charge to income for expenses related to a workforce reduction in ~~connection with our IPO.~~February 2020.

Commodity derivative gain (loss). Primarily due to the ~~increase~~decrease in NYMEX crude oil futures prices at ~~September 30, 2017~~March 31, 2020 as compared to ~~June 30, 2017~~December 31, 2019 and change in fair value from the execution of new positions, we incurred a net ~~loss~~gain on our commodity derivatives of ~~$37.9~~$263.0 million for the three months ended ~~September 30, 2017.~~March 31, 2020. Primarily due to the ~~decrease~~increase in NYMEX crude oil futures prices at ~~September 30, 2016~~March 31, 2019 as compared to ~~June 30, 2016~~December 31, 2018 and change in fair value from the execution of new positions, we incurred a net ~~gain~~loss on our commodity derivatives of ~~$16.2~~$122.1 million for the three months ended ~~September 30, 2016,~~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 ~~September 30, 2017,~~March 31, 2020, we received cash settlements of commodity derivatives totaling ~~$3.2~~$39.3 million. During the three months ended ~~September 30, 2016,~~March 31, 2019, we ~~received~~ ~~cash~~paid settlements of commodity derivatives totaling ~~$4.8~~$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~~long-term debt and amortization of ~~debt discount and~~ debt issuance costs, net of capitalized interest. For the three months ended ~~September 30, 2017,~~March 31, 2020, we recognized interest expense of ~~approximately $15.1~~$21.4 million as compared to ~~$31.2~~$13.0 million for the three months ended ~~September 30, 2016,~~March 31, 2019, as a result of borrowings under our revolving credit facility, ~~Second Lien Notes in 2016,~~ our ~~2021~~2024 Senior Notes, our ~~2024~~2026 Senior Notes and the amortization of debt issuance ~~costs and debt discount.~~costs.

We incurred interest expense for the three months ended ~~September 30, 2017~~March 31, 2020 of ~~approximately $16.5~~$22.3 million related to our ~~2021 Senior Notes,~~ 2024 Senior Notes, 2026 Senior Notes, and revolving credit facility. We incurred interest expense for the three months ended ~~September 30, 2016~~March 31, 2019 of approximately ~~$12.2~~$20.8 million related to our revolving credit facility, ~~Second Lien~~our 2024 Senior Notes, and our ~~2021~~2026 Senior Notes. Also included in interest expense for the three months ended ~~September 30, 2017~~March 31, 2020 and ~~2016~~2019 was the amortization of debt issuance costs ~~and debt discount~~ of ~~$1.5~~$1.2 million and ~~$15.9~~$1.5 million, respectively. For the three months ended ~~September 30, 2017~~March 31, 2020 and ~~2016,~~2019, we capitalized interest expense of ~~$2.9~~$2.1 million and ~~$1.2~~$2.0 million, respectively. ~~Also included in interest~~Interest expense for the three months ended ~~September 30, 2016 is a prepayment penalty~~March 31, 2019 also includes $7.3 million of ~~$4.3 million related to~~gain on debt extinguishment upon the ~~Company's repayment~~repurchase of ~~its Second Lien Notes in July 2016.~~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 ~~September 30, 2017 of $17.1 million, resulting~~March 31, 2020 and 2019, respectively. This resulted in an effective tax rate of approximately ~~36.5%.~~19.6% and 23.6% for the three months ended March 31, 2020 and 2019, respectively. Our effective tax rate for ~~2017~~the three months ended March 31, 2020 and 2019 differs from the U.S. statutory income tax ~~rate~~rates of 21.0% primarily due to the effects of state income taxes, estimated taxable permanent differences, and ~~estimated permanent taxable differences.~~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 ~~2017,~~the three months ending March 31, 2020, our ~~combined federal~~gathering and ~~state statutory tax rate was 38.0%.~~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 ~~September 30, 2016, we were not subject to U.S. federal income tax.~~

~~Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016~~

~~Oil sales revenues.~~ ~~Crude oil sales revenues~~ ~~increased~~ ~~by $133.7 million to $269.6 million for the nine months ended September 30, 2017 as compared to crude oil sales of $135.9 million for the nine months ended September 30, 2016. An~~ ~~increase~~ ~~in sales volumes between these periods contributed a $95.9 million~~ ~~positive~~ ~~impact, while an~~ ~~increase~~ ~~in crude oil prices contributed a $37.8 million~~ ~~positive~~ ~~impact.~~

~~For the nine months ended September 30, 2017, our crude oil sales averaged 23.8 MBbl/d. Our crude oil sales volume~~ ~~increased~~ 71% to 6,496 MBbl for the nine months ended September 30, 2017 compared to 3,808 MBbl for the nine months ended September 30, 2016. The volume increase is primarily due to an increase in production from the completion of 172 gross wells from October 1, 2016 to September 30, 2017, partially offset by the natural decline of our existing properties.

~~The average price we realized on the sale of crude oil was $41.50 per Bbl for the nine months ended September 30, 2017 compared to $35.68 per Bbl for the nine months ended September 30, 2016.~~

~~Natural gas sales revenues.~~ ~~Natural gas sales revenues~~ ~~increased~~ ~~by $35.4 million to $63.1 million for the nine months ended September 30, 2017 as compared to natural gas sales revenues of $27.7 million for the nine months ended September 30, 2016. An~~ ~~increase~~ ~~in sales volumes between these periods contributed an $19.1 million~~ ~~positive~~ ~~impact, while an~~ ~~increase~~ ~~in natural gas prices contributed a $16.3 million~~ ~~positive~~ ~~impact.~~

~~For the nine months ended September 30, 2017, our natural gas sales averaged 79.5 MMcf/d. Natural gas sales volumes~~ ~~increased~~ by 69% to 21,713 MMcf for the nine months ended September 30, 2017 as compared to 12,851 MMcf for the nine months ended September 30, 2016. The volume increase is primarily due to the completion of 172 gross wells from October 1, 2016 to September 30, 2017, partially offset by the natural decline on existing producing properties.

~~The average price we realized on the sale of our natural gas was $2.91 per Mcf for the nine months ended September 30, 2017 compared to $2.16 per Mcf for the nine months ended September 30, 2016.~~

~~NGL sales revenues.~~ ~~NGL sales revenues~~ ~~increased~~ ~~by $37.8 million to $57.6 million for the nine months ended September 30, 2017 as compared to NGL sales revenues of $19.8 million for the nine months ended September 30, 2016. An~~ ~~increase~~ ~~in sales volumes between these periods contributed a $16.3 million~~ ~~positive~~ ~~impact, while an~~ ~~increase~~ ~~in price contributed a $21.5 million~~ ~~positive~~ ~~impact.~~

~~For the nine months ended September 30, 2017, our NGL sales averaged 9.9 MBbl/d. NGL sales volumes~~ ~~increased~~ by 82% to 2,695 MBbl for the nine months ended September 30, 2017 as compared to 1,479 MBbl for the nine months ended September 30, 2016. The volume increase is primarily due to the completion of 172 gross wells from October 1, 2016 to September 30, 2017, 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 $21.36 per Bbl for the nine months ended September 30, 2017 compared to $13.37 per Bbl for the nine months ended September 30, 2016.~~

~~Lease operating expenses.~~ ~~Our LOE~~ ~~increased~~ by $35.0 million to $75.8 million for the nine months ended September 30, 2017, from $40.8 million for the nine months ended September 30, 2016. The increase in LOE was primarily the result of an increase in producing wells.

On a per unit basis, LOE increased from $5.49 per BOE sold for the nine months ended September 30, 2016 to $5.91 per BOE sold for the nine months ended September 30, 2017. The increase in LOE was comprised of an increase in T&G expense of $19.1 million for the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016 and an increase in operating expenses of $15.9 million for the nine months ended September 30, 2017 compared to the

nine months ended September 30, 2016. The increase in LOE was primarily the result of an increase in both residue natural gas and NGL sales volumes and realized prices, resulting in collectively higher T&G fees.

~~Production taxes.~~ ~~Our production taxes~~ ~~increased~~ by $16.4 million to $33.3 million for the nine months ended September 30, 2017 as compared to $16.9 million for the nine months ended September 30, 2016. The increase is primarily attributable to increased revenue as production taxes are calculated as a percentage of sales revenue. Production taxes as a percentage of sales revenue was 8.5% for the nine months ended September 30, 2017 as compared to 9.2% for the nine months ended September 30, 2016. The decrease in production taxes as a percentage of sales revenue relates to a change in the estimated tax rate for the nine months ended September 30, 2017.

~~Exploration expenses.~~ Our exploration expenses were $24.4 million for the nine months ended September 30, 2017. We recognized $16.9 million in expense attributable to the extension of certain leases, $1.4 million attributable to exploratory geological and geophysical costs and $5.7 million in impairment expense attributable to the abandonment and impairment of unproved properties for the nine months ended September 30, 2017. For the nine months ended September 30, 2016, we recognized $14.7 million in exploration expenses.

~~Depletion,~~March 31, 2020, depreciation ~~amortization and accretion expense.~~ ~~Our DD&A expense~~ ~~increased~~ $72.2 million to $213.5 million for the nine months ended September 30, 2017 as compared to $141.3 million for the nine months ended September 30, 2016. This increase is due to an increase in volumes sold for the nine months ended September 30, 2017 as sales ~~increased~~ by approximately 5,380 MBoe. On a per unit basis, DD&A expense decreased from $19.02 per BOE for the nine months ended September 30, 2016 to $16.67 per BOE for the nine months ended September 30, 2017.

~~Impairment of long lived assets.~~ ~~Our impairment~~ expense was $0.7 million for the nine months ended September 30, 2017. We recognized this expense when certain well equipment inventory was evaluated to have a net realizable value less than the associated carrying value, after it was determined to no longer be useful in our current drilling operations. We recognized $23.4 million of impairment expense for the nine months ended September 30, 2016. The impairment expense for the nine months ended September 30, 2016 is primarily related to impairment of the assets in our northern field. The future undiscounted cash flows did not exceed the carrying amount associated with the proved oil and gas properties in the northern field and it was determined that the proved oil and gas properties had no remaining fair value. Therefore, the full net book value of these proved oil and gas properties was impaired at September 30, 2016.

~~Other operating expenses.~~ Other operating expenses for the nine months ended September 30, 2017 is comprised of a $0.5 million loss on the sale of property and equipment. Other operating expenses for the nine months ended September 30, 2016 is comprised of a $0.9 million rig termination fee in January 2016.

~~General and administrative expenses.~~ ~~G&A expenses~~ ~~increased~~ by $42.7 million to $77.9 million for the nine months ended September 30, 2017 as compared to $35.2 million for the nine months ended September 30, 2016. This increase is primarily due to an increase in our employee head count and unit and stock-based compensation for the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016. On a per unit basis, G&A expense increased from $4.74 per BOE sold for the nine months ended September 30, 2016 to $6.08 per BOE sold for the nine months ended September 30, 2017.

Our G&A expenses include the non-cash expense for unit and stock-based compensation for equity awards granted to our employees and directors. For the nine months ended September 30, 2017, stock-based compensation expense was $46.7$1.1 million as ~~compared to unit-based compensation~~the gathering facility was placed into service during the fourth quarter of ~~$14.9 million for the nine months ended September 30, 2016. The increase is due to additional equity awards granted to employees as part~~2019. Please see Note 15—Segments in Part I, Item I, Financial Information of ~~our 2016 Long Term Incentive Plan that was adopted in October 2016 in connection with our IPO.~~this Quarterly Report.

~~Commodity derivative gain (loss).~~ ~~Primarily due to the decrease in NYMEX crude oil futures prices at September 30, 2017 as compared to December 31, 2016 and change in fair value from the execution of new positions, we incurred a net~~ ~~gain~~ on our commodity derivatives of $46.4 million for the nine months ended September 30, 2017. Primarily due to the increase in NYMEX crude oil futures prices at September 30, 2016 as compared to December 31, 2015 and change in fair value from the execution of new positions, we incurred a net ~~loss~~ on our commodity derivatives of $62.4 million for the nine months ended September 30, 2016, 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. 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 nine months ended

~~September 30, 2017, we~~ ~~paid~~ ~~cash settlements of commodity derivatives totaling $6.0 million. During the nine months ended September 30, 2016, we~~ ~~received~~ ~~cash settlements of commodity derivatives totaling $37.9 million.~~

~~Interest expense.~~ Interest expense consists of interest expense on our long term debt, amortization of debt discount and debt issuance costs, net of capitalized interest. For the nine months ended September 30, 2017, we recognized interest expense of approximately $33.8 million as compared to $57.9 million for the nine months ended September 30, 2016, as a result of borrowings under our revolving credit facility, Second Lien Notes in 2016, our 2021 Senior Notes, our 2024 Senior Notes and the amortization of debt issuance costs and debt discount.

We incurred interest expense for the nine months ended September 30, 2017 of approximately $39.2 million related to our 2024 Senior Notes, 2021 Senior Notes and credit facility. We incurred interest expense for the nine months ended September 30, 2016 of approximately $38.9 million related to our Second Lien Notes, our 2021 Senior Notes and credit facility. Also included in interest expense for the nine months ended September 30, 2017 and 2016 was the amortization of debt issuance costs and debt discount of $3.2 million and $18.3 million, respectively. For the nine months ended September 30, 2017 and 2016, we capitalized interest expense of $8.6 million and $3.6 million, respectively. Also included in interest expense for the nine months ended September 30, 2016 is a prepayment penalty of $4.3 million related to the Company's repayment of its Second Lien Notes in July 2016.

~~Income tax benefit.~~ We recorded an income tax benefit for the nine months ended September 30, 2017 of $7.6 million, resulting in effective tax rate of approximately 35.3%. Our effective tax rate for 2017 differs from the U.S. statutory income tax rate primarily due to the effects of state income taxes and estimated permanent taxable differences. For 2017, our combined federal and state statutory tax rate was 38.0%. For the nine months ended September 30, 2016, we were not subject to U.S. federal income tax.

Liquidity and Capital Resources

~~Our primary~~Current Financial Condition and Liquidity

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 ~~other factors,~~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 ~~also issue equity~~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 ~~debt securities if needed.~~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, ~~our Second Lien Notes,~~ proceeds from ~~the~~notes offerings ~~of our 2021 Senior Notes~~ and ~~2024 Senior Notes (please refer to~~ ~~Note 4 – Long Term Debt)~~,preferred stock offerings, equity provided by investors, including our management team, ~~proceeds~~cash from ~~the IPO and a private placement~~issuance of ~~our common~~preferred stock, and cash flows from ~~operations. To date, our~~divestitures and from the sale of oil, gas and NGL production. Our primary ~~use~~uses of capital ~~has~~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 ~~discount and debt~~ issuance costs, were approximately ~~$932.6~~$1,556.3 million and ~~$538.1~~$1,555.8 million at ~~September 30, 2017,~~March 31, 2020, and December 31, ~~2016,~~2019, respectively. We also have other contractual commitments, which are described in Note ~~11 –~~ 13—Commitments and Contingencies in Part I, Item I,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 ~~80%~~70% of our projected oil and natural gas production over a ~~one‑to‑~~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.

Based on current expectations, we believe we have sufficient liquidity through our existing cash balances, cash flow from operations and available borrowings under our revolving credit facility to execute our current capital program, excluding any acquisitions we may consummate, make our interest payments on the 2021 Senior Notes and 2024 Senior Notes and pay dividends on our Series A Preferred Stock.

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.

~~Our initial 2017 capital budget~~We had a Stock Repurchase Program that ended in 2019. During the three months ended March 31, 2019. Spending under this program was ~~approximately $795 million~~$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 ~~$935 million, substantially all of which we intend~~repurchase up to ~~allocate to the Core DJ Basin. We intend to allocate approximately $675 million to $775~~$100.0 million of our 2017 capital budget to the drilling of 185 to 190 gross operated wells and the completion of 190 to 195 gross operated wells, approximately $60 to $80 million of non-operated drilling and completion, and approximately $60 million to $80 million to undeveloped leasehold acquisitions, midstream, and other capital expenditures. We are currently running a three rig program and plan to remain with a three rig program throughout 2017.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)

For the Nine Months Ended
September 30,
2017 2016
Net cash provided by operating activities $ 141,736
$ 97,563
Net cash used in investing activities $ (995,062 ) $ (280,546 )
Net cash provided by financing activities $ 378,729
$ 87,263

~~Nine~~Three Months Ended ~~September 30, 2017~~March 31, 2020 Compared to ~~Nine~~Three Months Ended ~~September 30, 2016~~March 31, 2019

Net cash provided by operating activities. For the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2020 as compared to the ~~nine~~three months ended ~~September 30, 2016,~~March 31, 2019, our net cash provided by operating activities increased by ~~$44.2~~$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 ~~$148.3~~$76.9 million ~~from~~ ~~increased~~ ~~sales volumes and prices and~~primarily as a result of a decrease in cash due to changes in current assets and liabilities of $52.7 million for the nine months ended September 30, 2017 compared to September 30, 2016. Offsetting these increases was a decrease in settlements on commodity ~~derivatives of $51.9 million.~~prices.

Net cash used in investing activities. For the ~~nine~~three months ended ~~September 30, 2017 as compared to the nine months ended September 30, 2016, our~~March 31, 2020, net cash used in investing activities ~~increased~~decreased by ~~$714.5~~$92.7 million compared to the three months ended March 31, 2019 primarily ~~due to an increase~~as a result of ~~$798.8~~$45.0 million ~~used in acquisitions, drilling~~less spent on oil and ~~completion activities~~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 ~~nine~~three months ended ~~September 30, 2017 as compared to the nine months ended September 30, 2016. Offsetting this increase was the change in cash held in escrow of $84.2 million.~~

~~Net cash provided by financing activities.~~ ~~For the nine months ended September 30, 2017 as compared to the nine months ended September 30, 2016, our net cash provided by financing activities increased by $291.5 million,~~March 31, 2019 primarily as a result of ~~an increase of $419.9~~$28.5 million ~~from the issuance of debt and a reduction in our expenditures for debt issuance costs. The increase from the issuance of debt is primarily due~~spent to ~~the August 2017 issuance of our 2024~~repurchase 2026 Senior Notes ~~for~~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 ~~proceeds~~borrowings on the credit facility during the first quarter of ~~$392.6 million. Additionally, for the nine months ended September 30, 2017~~2019 were $40.0 million compared to ~~September 30, 2016 our net cash provided by financing activities decreased by $120.8 million related to the issuance of units~~none during the ~~nine months ended September 30, 2016 and $7.7 million related to dividend payments on our Series A Preferred Stock during the nine months ended September 30, 2017.~~first quarter of 2020.

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Working Capital

Our working capital deficit was ~~$8.6~~$144.6 million and $240.8 million at ~~September 30, 2017. Our working capital was $379.1 million at~~March 31, 2020 and December 31, ~~2016.~~2019, respectively. Our cash balances totaled ~~$114.1~~$32.0 million and ~~$588.7~~$32.4 million at ~~September 30, 2017~~March 31, 2020 and December 31, ~~2016,~~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 ~~cash flows from operating activities and availability under our revolving credit facility will be sufficient to fund our working capital needs. 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.

~~Debt Arrangements~~

Our revolving credit facility has a maximum credit amount of $1.5 billion, subject to a borrowing base, and all of our current and future subsidiaries are guarantors under such facility. Amounts repaid under our revolving credit facility may be re-borrowed from time to time, subject Due to the ~~terms~~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 ~~facility. For more information on the revolving credit facility, please~~year. Please see Note ~~4 — Long-Term Debt~~13—Commitments and Contingencies and Note 4—Going Concern in Part 1, Item 1. Financial Information of this Quarterly Report. ~~The revolving~~

Debt Arrangements

For details of our debt arrangements including our credit facility, ~~is secured by liens on substantially all of our properties.~~

In July 2016, we closed a private offering of our unsecured 7.875% Senior Notes due 2021 that resulted in net proceeds of approximately $537.2 million. Our 2021 Senior Notes bear interest at an annual rate of 7.875%. Interest on our 2021 Senior Notes is payable on January 15 and July 15 of each year, and the first interest payment was made on January 15, 2017. Our 2021 Senior Notes will mature on July 15, 2021. Our 2021 Senior Notes are guaranteed by all of our current and future restricted subsidiaries (other than Extraction Finance Corp., the co-issuer of our 2021 Senior Notes).

~~In August 2017, we closed a private offering of our unsecured 7.375% Senior Notes due 2024 that resulted in net proceeds of approximately $392.6 million. Our~~ 2024 Senior Notes ~~bear interest at an annual rate of 7.375%. Interest on our 2024~~and 2026 Senior Notes, ~~is payable on May 15~~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 ~~November 15 of each year commencing on November 15, 2017. Our 2024 Senior Notes will mature on May 15, 2024. Our 2024 Senior Notes~~Analysis section are ~~guaranteed by all of our current and future restricted subsidiaries.~~as follows.

~~Revolving Credit Facility~~

The amount available to be borrowed under our revolving credit facility is subject to a borrowing base that is redetermined semiannually on August 1, 2017 and each May 1 and November 1 thereafter, and will depend on the volumes of our proved oil and gas reserves and estimated cash flows from these reserves and other information deemed relevant by the administrative agent under our revolving credit facility. As of September 30, 2017, the borrowing base was $375.0 million, and there were no borrowings outstanding under our revolving credit facility. In October 2017, the Company completed the August 1, 2017 borrowing base redetermination. As a result of the redetermination, the borrowing base increased to $525.0 million.

Principal amounts borrowed will be payable on the maturity date, and interest will be payable quarterly for alternate base rate loans and at the end of the applicable interest period for Eurodollar loans. We have a choice of borrowing in Eurodollars or at the alternate base rate. Eurodollar loans bear interest at a rate per annum equal to an adjusted LIBOR rate (equal to the product of: (a) the LIBOR rate, multiplied by (b) a fraction (expressed as a decimal), the numerator of which is the number one and the denominator of which is the number one minus the reserve percentages (expressed as a decimal) on such date at which the administrative agent under our revolving credit facility is required to maintain reserves on ‘Eurocurrency Liabilities’ as defined in and pursuant to Regulation D of the Board of Governors of the Federal Reserve System) plus an applicable margin ranging from 200 to 300 basis points, depending on the percentage of our borrowing base utilized. Alternate base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the adjusted one-month LIBOR rate (as calculated above) plus 100 basis points, plus an applicable margin ranging from 100 to 200 basis points, depending on the percentage of our borrowing base utilized. As of September 30, 2017, we had no outstanding borrowings under our revolving credit facility. We may repay any amounts borrowed prior to the maturity date without any premium or penalty other than customary LIBOR breakage costs.

The revolving credit facility is secured by liens on substantially all of our properties and guarantees from us and our current and future subsidiaries. The revolving credit facility contains restrictive covenants that may limit our ability to, among other things:

~~incur additional indebtedness;~~

~~sell assets;~~

~~make loans to others;~~

~~make investments;~~

~~make certain changes to our capital structure;~~

~~make or declare dividends;~~

~~hedge future production or interest rates;~~

~~enter into transactions with our affiliates;~~

~~holding cash balances in excess of certain thresholds while carrying a balance of our revolving credit facility;~~

~~incur liens; and~~

~~engage in certain other transactions without the prior consent of the lenders.~~

~~The revolving credit facility requires us to maintain the following financial ratios:~~

a current ratio, which is the ratio of our consolidated current assets (includes unused commitments under our revolving credit facility and unrestricted cash and excludes derivative assets) to our consolidated current liabilities (excludes obligations under our revolving credit facility, the senior notes and certain derivative liabilities), of not less than 1.0 to 1.0 as of the last day of any fiscal quarter; and

a net leverage ratio, which is the ratio of (i) consolidated debt less cash balances to (ii) our consolidated EBITDAX for the four fiscal quarter period most recently ended, not to exceed 4.0 to 1.0 as of the last day of such fiscal quarter; provided that (a) for the quarter ended September 30, 2017, consolidated EBITDAX will be based on the last six months’ consolidated EBITDAX multiplied by 2, (b) for the quarter ending December 31, 2017, consolidated EBITDAX will be based on the last nine months' consolidated EBITDAX multiplied by 4/3, and (c) for the quarters ending on or after March 31, 2018, consolidated EBITDAX will be based on the last twelve months’ consolidated EBITDAX.

In August 2017, we amended and restated the revolving credit facility to, among other things, (i) increase the total aggregate commitment to $1.5 billion, subject to an initial borrowing base of $375.0 million, and (ii) increase the letter of credit sublimit to $50.0 million. The revolving credit facility matures on the earlier of (a) August 16, 2022, (b) January 15, 2021 if (and only if) the Company's 2021 Senior Notes (as defined below) have not been refinanced or repaid in full on or prior to January 15, 2021, (c) April 15, 2021, if (and only if) (i) the Series A Preferred Stock of the Company (the "Series A Preferred Stock") have not been converted into common equity or redeemed prior to April 15, 2021, 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 (d) the earlier termination in whole of the commitments.

In October 2017, we amended the revolving credit facility to, among other things, (i) provide for the joinder of new lenders, (ii) increase the borrowing base under the credit facility from $375.0 million to $525.0 million, and (iii) amend certain provisions of the credit agreement, including the commitments and allocations of each lender.

~~2021 Senior Notes~~

In July 2016, we closed a private offering of our 2021 Senior Notes that resulted in net proceeds of approximately $537.2 million. Our 2021 Senior Notes bear interest at an annual rate of 7.875%. Interest on our 2021 Senior Notes is payable on January 15 and July 15 of each year, and the first interest payment was made on January 15, 2017. Our 2021 Senior Notes will mature on July 15, 2021.

We may, at our option, redeem all or a portion of our 2021 Senior Notes at any time on or after July 15, 2018. We are also entitled to redeem up to 35% of the aggregate principal amount of our 2021 Senior Notes before July 15, 2018, with an amount of cash not greater than the net proceeds that we raise in certain equity offerings at a redemption price equal to 107.875% of the principal amount of our 2021 Senior Notes being redeemed plus accrued and unpaid interest, if any, to the redemption date. In addition, prior to July 15, 2018, we may redeem some or all of our 2021 Senior Notes at a price equal to 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date, plus a “make-whole” premium. If we experience certain kinds of changes of control, holders of our ~~2021~~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.

~~Our 2021 Senior Notes are our senior unsecured obligations and rank equally in right of payment with all~~Equity Arrangements

For details of our ~~other senior indebtedness and senior to any of~~equity arrangements including our subordinated indebtedness. Our 2021 Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by each of our current and future restricted subsidiaries (other than Extraction Finance Corp., the co-issuer of our 2021 Senior Notes) that guarantees our indebtedness under a credit facility. The notes are effectively

subordinated to all of our secured indebtedness (including all borrowings and other obligations under our 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 future subsidiaries that do not guarantee the notes.

~~2024 Senior Notes~~

In August 2017, we closed a private offering of our 2024 Senior Notes that resulted in net proceeds of approximately $392.6 million. Our 2024 Senior Notes bear interest at an annual rate of 7.375%. Interest on our 2024 Senior Notes is payable on May 15 and November 15 of each year, and the first interest payment will be due on November 15, 2017. Our 2024 Senior Notes will mature on May 15, 2024.

We may, at our option, redeem all or a portion of our 2024 Senior Notes at any time on or after May 15, 2020 at the redemption prices set forth in the indenture governing the 2024 Senior Notes. We are also entitled to redeem up to 35% of the aggregate principal amount of our 2024 Senior Notes before May 15, 2020, with an amount of cash not greater than the net proceeds that we raise in certain equity offerings at a redemption price equal to 107.375% of the principal amount of our 2024 Senior Notes being redeemed plus accrued and unpaid interest, if any, to the redemption date. In addition, prior to May 15, 2020, we may redeem some or all of our 2024 Senior Notes at a price equal to 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date, plus a “make-whole” premium. If we experience certain kinds of changes of control, holders of our 2024 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.

Our 2024 Senior Notes are our senior unsecured obligations and rank equally in right of payment with all of our other senior indebtedness and senior to any of our subordinated indebtedness. Our 2024 Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by each of our current subsidiaries and by certain future restricted subsidiaries that guarantees our indebtedness under a credit facility. The notes are effectively subordinated to all of our secured indebtedness (including all borrowings and other obligations under our 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 our future subsidiaries that do not guarantee the notes.

~~Series A Preferred Stock~~

The Company's Series A Preferred Stock (the "Series A Preferred Stock") 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). Each of 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 may elect to convert each share of Series A Preferred Stock at a conversion ratio of 61.9195, but only if the closing price of our common stock trades at or above a certain premium to our initial offering price, with such premiums decreasing with time. 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~~Elevation Preferred Units, please see Note 11—Equity in Part I, Item 1. Financial Information of return on the liquidation preference of the Series A Preferred Stock. The Series A Preferred Stock matures on October 15, 2021, at which time they are mandatorily redeemable for cash at the liquidation preference. For more information, see the Company’s Annualthis 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, ~~2016.~~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

~~In May 2017, the Financial~~Please see Note 2—Basis of Presentation, Significant Accounting ~~Standards Board (“FASB”) issued~~Policies and Recent Accounting ~~Standards Update (“ASU”) No. 2017-09, which provides clarification and reduces both (1) diversity~~ Pronouncements in practice and (2) cost and complexity when applying the guidance in Topic 718 Compensation - Stock Compensation, to a change to the terms or conditions of a share-based payment award. For public entities, the new guidance is effective for fiscal years beginning after December 15, 2017, including interim reporting periods within that reporting period. Early adoption is permitted for fiscal years beginning after December 15, 2016, including the interim reporting periods within that fiscal year. The Company is currently evaluating the impact of adopting this ASU, however it is not expected to have a significant effect on its consolidated financial statements.

In January 2017, the FASB issued ASU No. 2017-04, which simplifies how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. Step 2 measures a goodwill impairment loss by comparing the implied fair value of a reporting unit’s goodwill with the carrying amount. For public entities, the new guidance is effective for fiscal years beginning after December 15, 2019. Early adoption is permitted for interim and annual goodwill impairment tests performed on testing dates after JanuaryPart 1, ~~2017. The Company is currently evaluating this ASU and believes it could have a material impact to its financial statements and related disclosures.~~

In March 2016, the FASB issued ASU No. 2016-06, which clarifies the requirements to assess whether an embedded put or call option is clearly and closely related to the debt host, solely in accordance with the four step decision sequence in FASB ASB Topic 815, Derivatives and Hedging, as amended by this ASU. This standard is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016 and should be applied using a modified retrospective approach. The Company adopted this ASU in the first quarter of 2017 and the adoptionItem 1 of this ~~ASU did not have~~Quarterly Report for a ~~material impact on the its consolidated financial statements.~~detailed list of recent accounting pronouncements.

flows. It is effective for fiscal years commencing after December 15, 2018 and early adoption is permitted. In September 2017, the FASB issued ASU No. 2017-13, which provided additional implementation guidance. The Company is currently evaluating the impact this ASU will have on its financial statements and related disclosures and developing a strategy for implementation.

In May 2014, the FASB issued ASU No. 2014-09, which establishes a comprehensive new revenue recognition model designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. The ASU allows for the use of either the full or modified retrospective transition method. In August 2015, the FASB issued ASU No. 2015-14, which deferred ASU No. 2014-09 for one year, and is effective for annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. Earlier application is permitted only as of reporting periods beginning after December 15, 2016. The FASB subsequently issued ASU No. 2016-08, ASU No. 2016-10, ASU No. 2016-11, ASU No. 2016-12, ASU No. 2016-20, and ASU No. 2017-13, which provided additional implementation guidance. The Company is in the final stages of its review of contracts in each of its revenue streams and has developed accounting policies to address the provisions of this ASU. While the Company does not expect operating income (loss) to be materially impacted, the Company does expect total revenues and total expenses to change as a result of certain percentage of proceeds contracts. Further, the Company has begun evaluating the design of its pre-adoption and adoption controls and expects new or modification of certain controls to address risks associated with recognizing revenue under the new standard as we continue the implementation process. The Company will continue to evaluate the impact of this and other provisions of the ASU on its accounting policies, internal controls, and consolidated financial statements and related disclosures and has not finalized any estimates of the potential impacts. The Company will adopt this new standard on January 1, 2018, using the modified retrospective method with a cumulative adjustment to retained earnings.

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 ~~decline~~declining commodity prices. Historically, field-level prices received for our oil and natural gas production have been volatile. During the ~~years ended December 31, 2014 and 2015, commodity prices decreased, while during the~~ year ended December 31, ~~2016,~~2019, commodity prices increased ~~and remained stable~~ during the ~~nine~~first, second and third quarter, and subsequently decreased in the fourth quarter. During the three months ended ~~September 30, 2017.~~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.

~~The following tables present our~~For a summary of the Company’s commodity derivative ~~positions related to crude oil and natural gas sales in effect~~contracts as of ~~September 30, 2017:~~March 31, 2020, please see Note 6—Commodity Derivative Instruments in Part 1, Item 1 of this Quarterly Report.

December 31,
2017

March 31,
2018

June 30,
2018

September 30,
2018

December 31,
2018

March 31,
2019

June 30,
2019
NYMEX WTI⁽¹⁾ Crude Swaps:

Notional volume (Bbl) 1,850,000
1,500,000
1,500,000
1,050,000
1,050,000
—
—
Weighted average fixed price ($/Bbl) $ 50.64
$ 50.70
$ 50.70
$ 52.91
$ 52.91

NYMEX WTI⁽¹⁾ Crude Sold Calls:

Notional volume (Bbl) 1,200,000
1,735,000
1,335,000
1,560,000
1,560,000
1,500,000
1,500,000
Weighted average fixed price ($/Bbl) $ 53.04
$ 55.60
$ 56.22
$ 55.63
$ 55.63
$ 55.10
$ 55.10
NYMEX WTI⁽¹⁾ Crude Sold Puts:

Notional volume (Bbl) 3,225,000
3,269,400
3,269,400
2,400,000
2,400,000
1,500,000
1,500,000
Weighted average purchased put price ($/Bbl) $ 37.19
$ 38.14
$ 38.14
$ 40.00
$ 40.00
$ 39.70
$ 39.70
NYMEX WTI⁽¹⁾ Crude Purchased Calls:

Notional volume (Bbl) 450,000
285,000
285,000
210,000
210,000
—
—
Weighted average fixed price ($/Bbl) $ 61.65
$ 60.69
$ 60.69
$ 59.69
$ 59.69

NYMEX WTI⁽¹⁾ Crude Purchased Puts:

Notional volume (Bbl) 1,800,000
2,219,400
1,919,400
1,350,000
1,350,000
1,500,000
1,500,000
Weighted average purchased put price ($/Bbl) $ 42.13
$ 46.15
$ 45.71
$ 49.51
$ 49.51
$ 49.37
$ 49.37
NYMEX HH⁽²⁾ Natural Gas Swaps:

Notional volume (MMBtu) 7,420,000
10,500,000
9,300,000
8,700,000
8,700,000
—
—
Weighted average fixed price ($/MMBtu) $ 3.06
$ 3.30
$ 3.03
$ 3.03
$ 3.03

NYMEX HH⁽²⁾ Natural Gas Sold Calls:

Notional volume (MMBtu) —
600,000
600,000
600,000
600,000
—
—
Weighted average sold call price ($/MMBtu) $ 3.15
$ 3.15
$ 3.15
$ 3.15

NYMEX HH⁽²⁾ Natural Gas Purchased Puts:

Notional volume (MMBtu) —
600,000
600,000
600,000
600,000
—
—
Weighted average purchased put price ($/MMBtu) $ 3.00
$ 3.00
$ 3.00
$ 3.00

CIG⁽³⁾ Basis Gas Swaps:

Notional volume (MMBtu) 5,215,000
6,300,000
—
—
—
—
—
Weighted average fixed basis price ($/MMBtu) $ (0.31 ) $ (0.31 )


~~(1)~~	~~NYMEX WTI refers to West Texas Intermediate crude oil price on the New York Mercantile Exchange~~


~~(2)~~	~~NYMEX HH refers to the Henry Hub natural gas price on the New York Mercantile Exchange~~


~~(3)~~	~~CIG refers to the NYMEX HH settlement price less the fixed basis price, the Rocky Mountains (CIGC) settlement price.~~

As of ~~September 30, 2017,~~March 31, 2020, the fair market value of our oil derivative contracts was a net ~~liability~~asset of ~~$12.9~~$236.4 million. Based on our open oil derivative positions at ~~September 30, 2017,~~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 ~~liability~~asset by approximately ~~$69.9 million, while a 10% decrease in the NYMEX WTI price would decrease our net oil derivative liability by approximately $60.7~~$30.6 million. As of ~~September 30, 2017,~~March 31, 2020, the fair market value of our natural gas derivative contracts was a net asset of ~~$2.6~~$16.0 million. Based upon our open commodity derivative positions at ~~September 30, 2017,~~March 31, 2020, a 10% increase in the NYMEX Henry Hub price would decrease our net natural gas derivative asset by approximately ~~$13.6~~$3.8 million, while a 10% decrease in the NYMEX Henry Hub price would increase our net natural gas ~~derivate~~derivative asset by approximately ~~$13.6~~$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 ~~nine~~three months ended ~~September 30, 2017,~~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 ~~September 30, 2017,~~March 31, 2020, we had commodity derivative contracts with ~~six~~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. Three of the six counterparties to the derivative instruments are highly rated entities with corporate ratings at A3 classifications or above by Moody’s. The other three counterparties had a corporate rating of Baa1 by Moody’s. For the three ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2020 and ~~2016,~~2019, we did not incur any losses with respect to counterparty contracts. None of our existing derivative instrument contracts ~~contains~~contain credit risk related contingent features.

Interest Rate Risk

At ~~September 30, 2017,~~March 31, 2020, we had ~~no variable rate~~$470.0 million variable-rate debt outstanding. ~~Assuming we had the full amount of variable-rate debt outstanding available to us at September 30, 2017 of $375.0 million, the~~The impact on interest expense of a 1% increase or decrease in the average interest rate would be approximately ~~$3.8 million.~~$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.”

~~Off‑Balance Sheet Arrangements~~

As of September 30, 2017, we did not have any off-balance sheet arrangements other than operating leases, contractual commitments for drilling rigs, gathering commitments, and acquisitions of undeveloped leasehold acreage. Additionally, our oil marketer is subject to a firm transportation agreement with a make-whole provision that allows us to satisfy any minimum volume commitment deficiencies incurred by our oil marketer with future barrels of crude oil in excess of their minimum volume commitment through October 31, 2018. Please see ~~Note 11 – Commitments and Contingencies~~ ~~in Part 1, Item 1 of this Quarterly Report.~~

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

~~As required by Rule 13a-15(b) under the Securities Exchange Act of 1934 (the “Exchange Act”), we have evaluated, under the supervision and~~

Our management, with the participation of ~~management, including~~ our principal executive officer and principal financial officer, evaluated the effectiveness ~~of the design and operation~~ of our disclosure controls and procedures ~~(as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report on Form 10-Q. Our disclosure controls and procedures are designed~~ to ~~provide reasonable assurance~~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 and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC.~~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, ~~2017.~~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 ~~September 30, 2017~~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 be found in Note ~~11 –~~ 13—Commitments and Contingencies~~, to our condensed consolidated financial statements included elsewhere~~ — Litigation and Legal Items inPart I, Item 1. Financial Information in this ~~report.~~Quarterly Report.

We are currently in discussions with the Colorado Department of Public Health and Environment (“CDPHE”) regarding a Compliance Advisory issued to us in July 2015, which alleged air quality violations at three of our facilities regarding leakages of volatile organic compounds from storage tanks, all of which were promptly addressed. We continue to work with the CDPHE on its investigation into our facilities and it intends to seek a field-wide administrative settlement of these issues. At this time, we anticipate the remediation and compliance costs that this matter may impose upon us to be an immaterial amount.

From time to time, we may be involved in litigation relating to claims arising out of our business and operations in the normal course of business. As of the filing date of this report, no legal proceedings are pending against us that we believe individually or collectively could have a materially adverse effect upon our financial condition, results of operations or cash flows.

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”~~"Risk Factors", included in our Annual ~~Report.~~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

~~None.~~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:~~

(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~~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).

~~4.1~~†10.1

~~Indenture,~~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 ~~August 1, 2017, by~~as of March 4, 2020 , between the Company and ~~among Extraction Oil & Gas, Inc., the guarantors party thereto and Wells Fargo Bank, National Association, as trustee~~Thomas B. Tyree (incorporated by reference to Exhibit ~~4.1~~10.2 to the Company’s Current Report on Form 8-K (File No. 001-37907) filed with the Commission on ~~August 3, 2017)~~March 5, 2020).

~~4.2~~†10.3

~~Second Supplemental Indenture, dated December 22, 2016~~Indemnification Agreement (Thomas B. Tyree) (incorporated by reference to Exhibit 10.3 to the Company'sCurrent Report on Form 8-K (File No. 001-37907) filed with the Commission on March 5, 2020).

†10.4

Amended and ~~among~~ 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.~~, Extraction Finance Corp.,~~ Executive Severance Plan (incorporated by reference to Exhibit 10.5 to the ~~guarantors party thereto and Wells Fargo Bank, National Association, as trustee.~~Company’s Current Report on Form 8-K (File No. 001-37907) filed with the Commission on March 5, 2020).

~~4.3~~†10.6

~~Third Supplemental Indenture, dated June 29, 2017~~Form of Participation Agreement (Ex ecutive Se verance Plan)(incorporated by ~~and among Extraction Oil & Gas, Inc., Extraction Finance Corp.,~~reference to Exhibit 10.6 to the ~~guarantors party thereto and Wells Fargo Bank, National Association, as trustee.~~Company’s Current Report on Form8-K (File No. 001-37907) filed with the Commission on March 5, 2020).

*10.1†10.7

~~Amendment No. 12 to the Credit~~Employment Transition Agreement, dated as of May 5, 2017, by and among Extraction Oil & Gas, Inc., as borrower, certain subsidiaries of the Company, as guarantors, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto.

~~10.2~~

~~Amended and Restated Credit Agreement, dated as of August 16, 2017, by and~~March 18, 2020, between Extraction Oil & Gas, Inc., ~~as borrower, Wells Fargo Bank, National Association, as administrative agent~~XOG Services, LLC. and ~~issuing lender, and the lenders party thereto~~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 ~~August 21, 2017)~~March 20, 2020).

~~10.3~~†10.8

~~Increase~~Form of Restricted Stock Unit Award Agreement Joinder and Amendment No. 1 to Amended and Restated Credit Agreement, dated as of October 11, 2017, by and between Extraction Oil & Gas, Inc., as borrower, certain subsidiaries of the Company, as guarantors, Wells Fargo Bank, National Association, as administrative agent and issuing lender and the lenders party thereto (Performance -Vesting, Share-Settled) (for Officers) (incorporated by reference to Exhibit ~~10.1~~10.2 to the Company’s Current Report on Form 8-K (File No. 001-37907) filed with the Commission on ~~October 13, 2017)~~March 20, 2020).

*31.1†10.9

Form of Restricted Cash Award Agreement (Emplo yees)(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.

* 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: ~~November 7, 2017.~~May 11, 2020.


	Extraction Oil & Gas, Inc.

	~~Extraction Oil & Gas, Inc.~~By:	/S/ MATTHEW R. OWENS
		Matthew R. Owens
	~~By:~~	~~/S/ MARK A. ERICKSON~~
~~Mark A. Erickson~~
~~Chairman~~President and Chief Executive Officer (principal executive officer)



			By:			/S/ ~~RUSSELL T. KELLEY, JR.~~TOM L. BROCK
						~~Russell T. Kelley, Jr.~~Tom L. Brock
						Vice President and Chief ~~Financial~~Accounting Officer (principal financial officer)


	September 30, 2017			December 31, 2016				March 31, 2020		December 31, 2019
ASSETS							ASSETS
Current Assets:							Current Assets:
Cash and cash equivalents	$	114,139		$	588,736		Cash and cash equivalents	$	31,993	$	32,382
Accounts receivable							Accounts receivable
Trade	52,638			23,154			Trade	49,878		32,009
Oil, natural gas and NGL sales	70,425			34,066			Oil, natural gas and NGL sales	38,850		105,103
Inventory and prepaid expenses	13,262			7,722
Inventory, prepaid expenses and other							Inventory, prepaid expenses and other	34,494		36,702
Commodity derivative asset	986			—			Commodity derivative asset	164,330		17,554
Total Current Assets	251,450			653,678			Total Current Assets	319,545		223,750
Property and Equipment (successful efforts method), at cost:							Property and Equipment (successful efforts method), at cost:
Proved oil and gas properties	2,683,062			1,851,052			Proved oil and gas properties	4,676,967		4,530,934
Unproved oil and gas properties	639,867			452,577			Unproved oil and gas properties	417,021		524,214
Wells in progress	130,668			98,747			Wells in progress	154,981		149,733
Less: accumulated depletion, depreciation and amortization	(610,390		)	(402,912		)
Less: accumulated depletion, depreciation, amortization and impairment charges							Less: accumulated depletion, depreciation, amortization and impairment charges	(3,057,098)		(2,985,983)
Net oil and gas properties	2,843,207			1,999,464			Net oil and gas properties	2,191,871		2,218,898
Gathering systems and facilities, net of accumulated depreciation							Gathering systems and facilities, net of accumulated depreciation	—		315,777
Other property and equipment, net of accumulated depreciation	26,866			32,721			Other property and equipment, net of accumulated depreciation	72,589		72,542
Net Property and Equipment	2,870,073			2,032,185			Net Property and Equipment	2,264,460		2,607,217
Non-Current Assets:							Non-Current Assets:
Cash held in escrow	—			42,200
Goodwill and other intangible assets, net of accumulated amortization	54,966			54,489
Commodity derivative asset							Commodity derivative asset	88,783		13,229
Other non-current assets	11,611			2,224			Other non-current assets	30,600		82,761
Total Non-Current Assets	66,577			98,913			Total Non-Current Assets	119,383		95,990
Total Assets	$	3,188,100		$	2,784,776		Total Assets	$	2,703,388	$	2,926,957
LIABILITIES AND STOCKHOLDERS' EQUITY							LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:							Current Liabilities:
Accounts payable and accrued liabilities	$	151,940		$	131,134		Accounts payable and accrued liabilities	$	163,057	$	190,864
Accounts payable and accrued liabilities, related party							Accounts payable and accrued liabilities, related party	46,777		—
Revenue payable	41,209			35,162			Revenue payable	104,702		108,493
Production taxes payable	39,556			27,327			Production taxes payable	115,556		115,489
Commodity derivative liability	8,259			56,003			Commodity derivative liability	716		1,998
Accrued interest payable	14,068			19,621			Accrued interest payable	18,042		20,625
Asset retirement obligations	4,998			5,300			Asset retirement obligations	15,328		27,058
Total Current Liabilities	260,030			274,547			Total Current Liabilities	464,178		464,527
Non-Current Liabilities:							Non-Current Liabilities:
Credit facility							Credit facility	470,000		470,000
Senior Notes, net of unamortized debt issuance costs	932,570			538,141			Senior Notes, net of unamortized debt issuance costs	1,086,347		1,085,777
Production taxes payable	37,138			35,838			Production taxes payable	119,675		98,740
Commodity derivative liability	3,025			6,738			Commodity derivative liability	—		108
Other non-current liabilities	6,038			3,466			Other non-current liabilities	59,689		54,579
Asset retirement obligations	60,193			50,808			Asset retirement obligations	78,445		68,850
Deferred tax liability	98,470			106,026			Deferred tax liability	2,200		—
Total Non-Current Liabilities	1,137,434			741,017			Total Non-Current Liabilities	1,816,356		1,778,054
Total Liabilities	1,397,464			1,015,564			Total Liabilities	2,280,534		2,242,581
Commitments and Contingencies—Note 11
Series A Convertible Preferred Stock, $0.01 par value; 50,000,000 shares authorized; 185,280 issued and outstanding	156,995			153,139
Commitments and Contingencies—Note 13							Commitments and Contingencies—Note 13
Series A Convertible Preferred Stock, $0.01 par value; 50,000,000 shares authorized, 185,280 issued and outstanding							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:							Stockholders' Equity:
Common stock, $0.01 par value; 900,000,000 shares authorized; 171,893,157 and 171,834,605 issued and outstanding	1,718			1,718
Common stock, $0.01 par value; 900,000,000 share authorized; 137,891,740 and 137,657,922 issued and outstanding, respectively							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							Treasury stock, at cost, 38,859,078 shares	(170,138)		(170,138)
Additional paid-in capital	2,101,103			2,067,590			Additional paid-in capital	2,143,670		2,156,383
Treasury stock, at cost, 165,385 and 0 shares	(2,105		)	—
Accumulated deficit	(467,075		)	(453,235		)	Accumulated deficit	(1,734,171)		(1,743,208)
Total Extraction Oil & Gas, Inc. Stockholders' Equity							Total Extraction Oil & Gas, Inc. Stockholders' Equity	240,697		244,373
Noncontrolling interest							Noncontrolling interest	—		264,364
Total Stockholders' Equity	1,633,641			1,616,073			Total Stockholders' Equity	240,697		508,737
Total Liabilities and Stockholders' Equity	$	3,188,100		$	2,784,776		Total Liabilities and Stockholders' Equity	$	2,703,388	$	2,926,957



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



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



			EXTRACTION OIL & GAS, INC.
			(Exact name of registrant as specified in its charter)



						~~(720) 557-8300~~
	(Registrant’s telephone number, including area code)


	For the Three Months Ended September 30,						For the Nine Months Ended September 30,							For the Three Months Ended March 31,
	2017			2016			2017			2016				2020		2019
Revenues:													Revenues:
Oil sales	$	132,075		$	51,760		$	269,597		$	135,896		Oil sales	$	124,219	$	165,424
Natural gas sales	24,672			12,792			63,095			27,730			Natural gas sales	22,302		35,892
NGL sales	24,114			8,350			57,574			19,773			NGL sales	17,193		20,601
Gathering and compression													Gathering and compression	1,473		—
Total Revenues	180,861			72,902			390,266			183,399			Total Revenues	165,187		221,917
Operating Expenses:													Operating Expenses:
Lease operating expenses	29,267			15,480			75,755			40,819
Lease operating expense													Lease operating expense	30,390		21,857
Midstream operating expenses													Midstream operating expenses	3,935		—
Transportation and gathering													Transportation and gathering	22,786		10,365
Production taxes	16,290			6,186			33,254			16,935			Production taxes	13,454		18,129
Exploration expenses	7,181			5,985			24,431			14,735
Exploration and abandonment expenses													Exploration and abandonment expenses	112,480		6,194
Depletion, depreciation, amortization and accretion	94,220			46,680			213,483			141,317			Depletion, depreciation, amortization and accretion	76,051		118,770
Impairment of long lived assets	—			467			675			23,350			Impairment of long lived assets	775		8,248
Gain on sale of property and equipment													Gain on sale of property and equipment	—		(222)
General and administrative expense													General and administrative expense	10,596		27,652
Other operating expenses	—			—			451			891			Other operating expenses	52,575		—
Acquisition transaction expenses	—			345			68			345
General and administrative expenses	28,741			20,071			77,916			35,189
Total Operating Expenses	175,699			95,214			426,033			273,581			Total Operating Expenses	323,042		210,993
Operating Income (Loss)	5,162			(22,312		)	(35,767		)	(90,182		)	Operating Income (Loss)	(157,855)		10,924
Other Income (Expense):													Other Income (Expense):
Commodity derivatives gain (loss)	(37,875		)	16,225			46,423			(62,424		)
Commodity derivative gain (loss)													Commodity derivative gain (loss)	263,015		(122,091)
Loss on deconsolidation of Elevation Midstream, LLC													Loss on deconsolidation of Elevation Midstream, LLC	(73,139)		—
Interest expense	(15,080		)	(31,216		)	(33,761		)	(57,914		)	Interest expense	(21,358)		(13,008)
Other income	891			36			1,709			120			Other income	574		1,143
Total Other Income (Expense)	(52,064		)	(14,955		)	14,371			(120,218		)	Total Other Income (Expense)	169,092		(133,956)
Loss Before Income Taxes	(46,902		)	(37,267		)	(21,396		)	(210,400		)
Income tax benefit	(17,106		)	—			(7,556		)	—
Net Loss	$	(29,796	)	$	(37,267	)	$	(13,840	)	$	(210,400	)
Loss Per Common Share (Note 10)
Income (Loss) Before Income Taxes													Income (Loss) Before Income Taxes	11,237		(123,032)
Income tax (expense) benefit													Income tax (expense) benefit	(2,200)		29,000
Net Income (Loss)													Net Income (Loss)	$	9,037	$	(94,032)
Net income attributable to noncontrolling interest													Net income attributable to noncontrolling interest	6,160		3,975
Net Income (Loss) Attributable to Extraction Oil & Gas, Inc.													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													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													Net Loss Available to Common Shareholders, Basic and Diluted	$	(3,641)	$	(102,324)
Loss Per Common Share (Note 12)													Loss Per Common Share (Note 12)
Basic and diluted	$	(0.20	)				$	(0.15	)				Basic and diluted	$	(0.03)	$	(0.60)
Weighted Average Common Shares Outstanding													Weighted Average Common Shares Outstanding
Basic and diluted	171,845						171,838						Basic and diluted	137,726		170,702



Purchase Price	June 8, 2017
Consideration given
Cash	$	13,395
Total consideration given	$	13,395
Allocation of Purchase Price
Proved oil and gas properties	$	13,495
Total fair value of oil and gas properties acquired	$	13,495
Asset retirement obligations	$	(100	)
Fair value of net assets acquired	$	13,395



Purchase Price	October 3, 2016
Consideration given
Cash	$	405,335
Total consideration given	$	405,335
Allocation of Purchase Price
Proved oil and gas properties	$	252,522
Unproved oil and gas properties	109,800
Total fair value of oil and gas properties acquired	$	362,322
Goodwill ⁽¹⁾	$	54,220
Working capital	(7,185		)
Asset retirement obligations	(4,022		)
Fair value of net assets acquired	$	405,335
Working capital acquired was estimated as follows:
Accounts receivable	$	955
Revenue payable	(3,012		)
Production taxes payable	(4,244		)
Accrued liabilities	(884		)
Total working capital	$	(7,185	)



Purchase Price	August 23, 2016
Consideration given
Cash	$	17,504
Total consideration given	$	17,504
Allocation of Purchase Price
Proved oil and gas properties	$	12,362
Unproved oil and gas properties	8,566
Total fair value of oil and gas properties acquired	$	20,928
Working capital	$	(9	)
Asset retirement obligations	(3,415		)
Fair value of net assets acquired	$	17,504
Working capital acquired was estimated as follows:
Production taxes payable	$	(9	)
Total working capital	$	(9	)



Borrowing Base Utilization Percentage	Utilization	Eurodollar Margin	Base Rate Margin	Commitment Fee Rate
Level 1	< 25%	2.00%	1.00%	0.375%
Level 2	≥ 25% < 50%	2.25%	1.25%	0.375%
Level 3	≥ 50% < 75%	2.50%	1.50%	0.500%
Level 4	≥ 75% < 90%	2.75%	1.75%	0.500%
Level 5	≥ 90%	3.00%	2.00%	0.500%



	As of September 30, 2017
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	$	25,250		$	(24,264	)	$	986		$	(146	)	$	840
Non-current assets	$	25,141		$	(25,141	)	$	—		$	—		$	—
Current liabilities	$	(32,523	)	$	24,264		$	(8,259	)	$	146		$	(11,138	)
Non-current liabilities	$	(28,166	)	$	25,141		$	(3,025	)	$	—		$	—



	As of December 31, 2016
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	$	12,620		$	(12,620	)	$	—		$	—	$	—
Non-current assets	$	14,993		$	(14,993	)	$	—		$	—	$	—
Current liabilities	$	(68,623	)	$	12,620		$	(56,003	)	$	—	$	(62,741	)
Non-current liabilities	$	(21,731	)	$	14,993		$	(6,738	)	$	—	$	—



	For the Nine Months Ended September 30, 2017			For the Year Ended December 31, 2016
Balance beginning of period	$	56,108		$	44,367
Liabilities incurred or acquired	6,644			8,945
Liabilities settled	(1,408		)	(1,155		)
Revisions in estimated cash flows	—			(1,695		)
Accretion expense	3,847			5,646
Balance end of period	$	65,191		$	56,108



	At September 30, 2017				At December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
2021 Senior Notes⁽¹⁾	$	539,804	$	580,250	$	538,141	$	588,500
2024 Senior Notes⁽²⁾	$	392,766	$	419,000	$	—	$	—



	Number of Options	Weighted Average Exercise Price
Non-vested Stock Options at January 1, 2017	4,500,000	$	19.00
Granted	—	$	—
Forfeited	—	$	—
Vested	—	$	—
Non-vested Stock Options at September 30, 2017	4,500,000	$	19.00



	Number of Shares	Weighted Average Grant Date Fair Value
Non-vested RSUs at January 1, 2017	3,237,500	$	21.41
Granted	1,305,033	$	16.43
Forfeited	(403,725)	$	19.72
Vested	(85,994)	$	16.82
Non-vested RSUs at September 30, 2017	4,052,814	$	20.07



	Number of Shares	Weighted Average Grant Date Fair Value
Non-vested Incentive RSUs at January 1, 2017	2,714,368	$	20.45
Granted	—	$	—
Forfeited	(703,868)	$	20.45
Vested	(507,200)	$	20.45
Non-vested Incentive RSUs at September 30, 2017	1,503,300	$	20.45



	For the Three Months Ended September 30, 2017			For the Nine Months Ended September 30, 2017
Basic and Diluted Loss Per Share
Net Loss	$	(29,796	)	$	(13,840	)
Less: Adjustment to reflect Series A Preferred Stock dividend	(2,721		)	(8,164		)
Less: Adjustment to reflect accretion of Series A Preferred Stock discount	(1,365		)	(3,992		)
Adjusted net loss available to common shareholders, basic and diluted	$	(33,882	)	$	(25,996	)
Denominator:
Weighted average common shares outstanding, basic and diluted⁽¹⁾	171,845			171,838
Loss Per Common Share
Basic and diluted	$	(0.20	)	$	(0.15	)



	For the Three Months Ended September 30,		For the Nine Months Ended September 30,
	2017	2016	2017	2016
Oil (MBbl)	3,184	1,290	6,496	3,808
Natural gas (MMcf)	8,953	4,792	21,713	12,851
NGL (MBbl)	1,109	574	2,695	1,479
Total (MBoe)	5,785	2,663	12,809	7,429
Average net sales (BOE/d)	62,884	28,948	46,921	27,114



	For the Three Months Ended				For the Nine Months Ended
	September 30,				September 30,
	2017		2016		2017		2016
Sales (MBoe)⁽¹⁾:	5,785		2,663		12,809		7,429
Oil sales (MBbl)	3,184		1,290		6,496		3,808
Natural gas sales (MMcf)	8,953		4,792		21,713		12,851
NGL sales (MBbl)	1,109		574		2,695		1,479
Sales (BOE/d)⁽¹⁾:	62,884		28,948		46,921		27,114
Oil sales (Bbl/d)	34,607		14,025		23,794		13,899
Natural gas sales (Mcf/d)	97,311		52,083		79,536		46,902
NGL sales (Bbl/d)	12,059		6,242		9,871		5,397
Average sales prices⁽²⁾:
Oil sales (per Bbl)	$	41.48	$	40.11	$	41.50	$	35.68
Oil sales with derivative settlements (per Bbl)	42.14		42.73		40.61		41.93
Natural gas sales (per Mcf)	2.76		2.67		2.91		2.16
Natural gas sales with derivative settlements (per Mcf)	2.84		2.94		2.90		2.84
NGL sales (per Bbl)	21.74		14.54		21.36		13.37
Average price (per BOE)	31.26		27.38		30.47		24.69
Average price with derivative settlements (per BOE)	31.76		29.12		30.00		29.06
Expense per BOE:
Lease operating expenses	$	5.06	$	5.81	$	5.91	$	5.49
Operating expenses	2.67		3.57		3.25		3.46
Transportation and gathering	2.39		2.24		2.66		2.03
Production taxes	2.82		2.32		2.60		2.28
Exploration expenses	1.24		2.25		1.91		1.98
Depletion, depreciation, amortization and accretion	16.29		17.53		16.67		19.02
Impairment of long lived assets	—		0.18		0.05		3.14
Other operating expenses	—		—		0.04		0.12
Acquisition transaction expenses	—		0.13		0.01		0.05
General and administrative expenses	4.97		7.54		6.08		4.74
Cash general and administrative expenses	1.84		2.92		2.43		2.73
Unit and stock-based compensation	3.13		4.62		3.65		2.01
Total operating expenses per BOE	$	30.38	$	35.76	$	33.27	$	36.82



	December 31, 2017			March 31, 2018			June 30, 2018		September 30, 2018		December 31, 2018		March 31, 2019		June 30, 2019
NYMEX WTI⁽¹⁾ Crude Swaps:
Notional volume (Bbl)	1,850,000			1,500,000			1,500,000		1,050,000		1,050,000		—		—
Weighted average fixed price ($/Bbl)	$	50.64		$	50.70		$	50.70	$	52.91	$	52.91
NYMEX WTI⁽¹⁾ Crude Sold Calls:
Notional volume (Bbl)	1,200,000			1,735,000			1,335,000		1,560,000		1,560,000		1,500,000		1,500,000
Weighted average fixed price ($/Bbl)	$	53.04		$	55.60		$	56.22	$	55.63	$	55.63	$	55.10	$	55.10
NYMEX WTI⁽¹⁾ Crude Sold Puts:
Notional volume (Bbl)	3,225,000			3,269,400			3,269,400		2,400,000		2,400,000		1,500,000		1,500,000
Weighted average purchased put price ($/Bbl)	$	37.19		$	38.14		$	38.14	$	40.00	$	40.00	$	39.70	$	39.70
NYMEX WTI⁽¹⁾ Crude Purchased Calls:
Notional volume (Bbl)	450,000			285,000			285,000		210,000		210,000		—		—
Weighted average fixed price ($/Bbl)	$	61.65		$	60.69		$	60.69	$	59.69	$	59.69
NYMEX WTI⁽¹⁾ Crude Purchased Puts:
Notional volume (Bbl)	1,800,000			2,219,400			1,919,400		1,350,000		1,350,000		1,500,000		1,500,000
Weighted average purchased put price ($/Bbl)	$	42.13		$	46.15		$	45.71	$	49.51	$	49.51	$	49.37	$	49.37
NYMEX HH⁽²⁾ Natural Gas Swaps:
Notional volume (MMBtu)	7,420,000			10,500,000			9,300,000		8,700,000		8,700,000		—		—
Weighted average fixed price ($/MMBtu)	$	3.06		$	3.30		$	3.03	$	3.03	$	3.03
NYMEX HH⁽²⁾ Natural Gas Sold Calls:
Notional volume (MMBtu)	—			600,000			600,000		600,000		600,000		—		—
Weighted average sold call price ($/MMBtu)				$	3.15		$	3.15	$	3.15	$	3.15
NYMEX HH⁽²⁾ Natural Gas Purchased Puts:
Notional volume (MMBtu)	—			600,000			600,000		600,000		600,000		—		—
Weighted average purchased put price ($/MMBtu)				$	3.00		$	3.00	$	3.00	$	3.00
CIG⁽³⁾ Basis Gas Swaps:
Notional volume (MMBtu)	5,215,000			6,300,000			—		—		—		—		—
Weighted average fixed basis price ($/MMBtu)	$	(0.31	)	$	(0.31	)