Supplemental cash flow information:
Property and equipment included in accounts payable and accrued liabilities $ 223,527
$ 197,577
Cash paid for interest $ 45,648
$ 41,607
Issuance of promissory note to unconsolidated subsidiary $ —
$ 35,329
Extinguishment of promissory note in exchange for equity with unconsolidated subsidiary $ —
$ (35,329 )
Accretion of beneficial conversion feature of Series A Preferred Stock $ 3,233
$ 2,914
Preferred Units commitment fees and dividends paid-in-kind $ 8,073
$ —

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

~~THESE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

EXTRACTION OIL & GAS, INC.

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 1—Business and Organization

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

Elevation Midstream, LLC (“Elevation”), a Delaware limited liability company and an unrestricted subsidiary of the Company, is focused on the construction of gathering systems and facilities operations to serve the development of acreage in the Company’s Hawkeye and Southwest Wattenberg areas. Midstream assets of Elevation are represented as the gathering systems and facilities line item within the condensed consolidated balance sheets. As of ~~June~~September 30, 2019, these gathering systems and facilities operations ~~are~~were not in service, therefore, there ~~are~~were no associated revenues for the three and ~~six~~nine months then ended. On October 3, 2019, Elevation commenced moving crude oil, natural gas and water through its Badger central gathering facility, which enables Extraction to efficiently transport its crude oil and natural gas production along with water used during the completion process. The use of this gathering facility allows for the elimination of oil or water storage on the well pad site and reduces truck traffic, which minimizes the impact to the surrounding environment and communities.

On July 10, 2019, Elevation closed on the issuance of an additional 100,000 Preferred Units of Elevation (the "Elevation Preferred Units") under ~~the~~an existing securities purchase agreement with a third party, pursuant to which Elevation had agreed to sell an additional 100,000 Elevation Preferred Units ~~of Elevation~~ at a price of $990 per Elevation Preferred Unit with an aggregate liquidation preference of $100.0 million, and ~~resulted~~resulting in net proceeds of approximately ~~$99.0 million.~~$96.5 million, after deducting discounts and related offering expenses. These Elevation Preferred Units are non-recourse to Extraction.

On November 19, 2018, the Company announced that the Board of Directors had authorized a program to repurchase up to $100.0 million of the Company's common stock ("Stock Repurchase Program"). On April 1, 2019, the Company announced the Board of Directors had authorized an extension and increase ~~in its~~to the ongoing Stock Repurchase Program bringing the total amount authorized to $163.2 million ("Extended Stock Repurchase Program"). ~~The~~Prior to commencing the Extended Stock Repurchase Program, the Company had purchased approximately 13.0 million shares of its common stock for $63.2 million under the Stock Repurchase ~~Program, prior to the Extended Stock Repurchase~~ Program. The Company iswas authorized to repurchase an incremental $100.0 million in common stock, ~~from~~which repurchases were completed in the ~~date~~third quarter of ~~the Extended Stock Repurchase Program,~~2019, bringing the total amount ~~authorized to be~~of common stock repurchased to ~~approximately~~ $163.2 million. The Company's Stock Repurchase Program does not obligate it to acquire any specific number of shares and will expire on December 31, 2019. The Company intends to conduct any open market stock repurchase activities in compliance with the safe harbor provisions of Rule 10b-18 of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). During the three and ~~six~~nine months ended ~~June~~September 30, 2019, the Company repurchased approximately ~~21.7~~4.8 million ~~shares~~ and ~~29.4~~34.1 million shares of its common stock for ~~$84.3~~$21.2 million and ~~$115.7~~$136.9 million, respectively. ~~Subsequent to June 30, 2019 through the date of this filing, the Company repurchased approximately 4.8 million additional shares of its common stock for $21.2 million.~~

Note 2—Basis of Presentation, Restatement, 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 statements and the year-end balance sheet 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.

Restatement of Previously Issued Unaudited Condensed Consolidated Financial Statements

The Company concluded subsequent to filing Form 10Q/A Amendment No. 1 with the SEC that one of the Company's revenue contracts should have been accounted for with an earlier termination date due to an automatic renewal provision. The contract term impacts the amount of consideration that can be included in the transaction price. The Company had accounted

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for revenue relating to the contract assuming a term ending in August 2023. Upon subsequent review, the Company determined that the proper accounting treatment pursuant to ASC 606 - Revenue from Contracts with Customers would have been to evaluate the contract with a term ending on April 30, 2021 because the contract may be terminated by either party with no penalty effective as of such date. However, the contract cannot be extended beyond October 2026. Accounting for the contract with an earlier termination date resulted in a decrease to the Company’s revenues of $20.0 million for the three and nine months ended September 30, 2019 and an increase to the Company's assets and liabilities of $12.3 million and $32.3 million as of September 30, 2019, respectively. Corrections to prior periods were immaterial. The following tables present the effect of the correction discussed above on selected line items of our previously reported condensed consolidated balance sheet as of September 30, 2019, and the Company's condensed consolidated statements of operations for the three and nine months ended September 30, 2019 and the Company's condensed consolidated statements of cash flows for the nine months ended September 30, 2019 (in thousands).

Condensed Consolidated Balance Sheet


	September 30, 2019
	As Reported		Adjustments		As Restated
Inventory, prepaid expenses and other	$	19,489	$	9,365	$	28,854
Total Current Assets	268,542		9,365		277,907
Other non-current assets	66,346		2,944		69,290
Total Non-Current Assets	107,866		2,944		110,810
Total Assets	4,429,158		12,309		$	4,441,467

Accounts payable and accrued liabilities	216,193		1		216,194
Total Current Liabilities	471,108		1		471,109
Other non-current liabilities	23,412		32,340		55,752
Deferred tax liability	115,876		(5,800)		110,076
Total Non-Current Liabilities	1,912,648		26,540		1,939,188
Total Liabilities	2,383,756		26,541		2,410,297
Accumulated deficit	(378,220)		(14,232)		(392,452)
Total Extraction Oil & Gas, Inc. Stockholders' Equity	1,617,899		(14,232)		1,603,667
Total Stockholders' Equity	1,876,120		(14,232)		1,861,888
Total Liabilities and Stockholders' Equity	$	4,429,158	$	12,309	$	4,441,467

Condensed Consolidated Statements of Operations


	Three Months Ended September 30, 2019
	As Reported		Adjustments		As Restated
Oil sales	$	171,074	$	(20,032)	$	151,042
Total Revenues	196,974		(20,032)		176,942
Operating Income (Loss)	2,687		(20,032)		(17,345)
Income (Loss) Before Income Taxes	68,756		(20,032)		48,724
Income tax expense	(20,600)		5,800		(14,800)
Net Income (Loss)	48,156		(14,232)		33,924
Net Income (Loss) Attributable to Extraction Oil & Gas, Inc.	42,380		(14,232)		28,148
Net Income (Loss) Attributable to Common Shareholders	37,977		(14,232)		23,745
Income (Loss) Per Common Share (Note 10)	0.28		(0.11)		0.17

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	Nine Months Ended September 30, 2019
	As Reported		Adjustments		As Restated
Oil sales	$	521,623	$	(20,032)	$	501,591
Total Revenues	640,948		(20,032)		620,916
Operating Income (Loss)	16,344		(20,032)		(3,688)
Income (Loss) Before Income Taxes	4,268		(20,032)		(15,764)
Income tax expense	(6,700)		5,800		(900)
Net Income (Loss)	(2,432)		(14,232)		(16,664)
Net Income (Loss) Attributable to Extraction Oil & Gas, Inc.	(16,281)		(14,232)		(30,513)
Net Income (Loss) Attributable to Common Shareholders	(29,360)		(14,232)		(43,592)
Income (Loss) Per Common Share (Note 10)	(0.19)		(0.09)		(0.28)

Condensed Consolidated Statements of Cash Flows


	Nine Months Ended September 30, 2019
	As Reported		Adjustments		As Restated
Net income (loss)	$	(2,432)	$	(14,232)	$	(16,664)
Contract asset (liability)	—		22,175		22,175
Deferred income tax expense	6,700		(5,800)		900
Inventory, prepaid expenses and other	(3,479)		4,557		1,078
Accounts payable and accrued liabilities	231		(6,700)		(6,469)
Net cash provided by operating activities	356,561		—		356,561

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

During the third quarter of 2019, the Company allocated $22.2 million to a satisfied performance obligation, recognized within oil sales for the three and nine months ended September 30, 2019, pursuant to Accounting Standards Codification ("ASC") 606, Revenue Recognition. Also, during the third quarter of 2019, the Company estimated a performance obligation under ASC 606 - Revenue from Contracts with Customers of $39.0 million, of which $3.4 million is recorded in accounts payable and accrued liabilities and $35.6 million is recorded in other non-current liabilities. A corresponding asset was recorded in the amount of $16.9 million, of which $10.4 million is recorded in inventory, prepaid expenses and other and $6.5 million is recorded in other non-current assets. These amounts were included in the condensed consolidated balance sheet as of September 30, 2019.

Leases

The Company accounts for leases in accordance with ~~Accounting Standards Codification ("ASC")~~ASC 842, Leases, which it adopted on January 1, 2019, applying the modified retrospective transition approach as of the effective date of adoption (see "Recent Accounting Pronouncements" for impacts of adoption).

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

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

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

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

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

For the three and ~~six~~nine months ended ~~June~~September 30, 2019, lease costs, which represent the straight-line lease expense of right-of-use ("ROU") assets and short-term leases, were as follows (in thousands):


	Three Months Ended June 30, 2019		Six Months Ended June 30, 2019			Three Months Ended September 30, 2019		Nine Months Ended September 30, 2019
Lease Costs included in the Condensed Consolidated Balance Sheets					Lease Costs included in the Condensed Consolidated Balance Sheets
Proved oil and gas properties, including drilling, completions and ancillary equipment, and gathering systems and facilities ⁽¹⁾	$	81,717	$	138,917	Proved oil and gas properties, including drilling, completions and ancillary equipment, and gathering systems and facilities ⁽¹⁾	$	92,023	$	230,940

Lease Costs included in the Condensed Consolidated Statements of Operations					Lease Costs included in the Condensed Consolidated Statements of Operations
Lease operating expenses ⁽²⁾	$	7,625	$	13,417
Operating lease costs ⁽²⁾					Operating lease costs ⁽²⁾	$	9,210	$	22,627
General and administrative expenses ⁽³⁾	953		1,757		General and administrative expenses ⁽³⁾	$	1,054	$	2,811
Total operating lease costs	8,578		15,174		Total operating lease costs	$	10,264	$	25,438

Total lease costs	$	90,295	$	154,091	Total lease costs	$	102,287	$	256,378


Borrowing Base Utilization Percentage	Utilization	Eurodollar Margin		Base Rate Margin		Commitment Fee Rate
Level 1	< 25%	1.50	%	0.50	%	0.375	%
Level 2	≥ 25% < 50%	1.75	%	0.75	%	0.375	%
Level 3	≥ 50% < 75%	2.00	%	1.00	%	0.500	%
Level 4	≥ 75% < 90%	2.25	%	1.25	%	0.500	%
Level 5	≥ 90%	2.50	%	1.50	%	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. Additionally, the credit facility limits the Company entering into hedges in excess of 85% of its anticipated production volumes.

The credit facility also contains financial covenants requiring the Company to comply on the last day of each quarter with a current ratio of its restricted subsidiaries’ current assets (includes availability under the revolving credit facility and unrestricted cash and excludes derivative assets) to its restricted subsidiaries’ current liabilities (excludes obligations under the revolving credit facility, senior notes and certain derivative liabilities), of not less than 1.0 to 1.0 and to maintain, on the last day of each quarter, a ratio of its restricted subsidiaries’ debt less cash balances to its restricted subsidiaries EBITDAX (EBITDAX is defined as net income adjusted for interest expense, income tax expense/benefit, DD&A, exploration expenses as well as certain non-recurring cash and non-cash charges and income (such as stock-based compensation expense, unrealized gains/losses on commodity derivatives and impairment of long-lived assets), subject to pro forma adjustments for non-ordinary course acquisitions and divestitures) for the ~~four~~4 fiscal quarter period most recently ended, of not greater than 4.0:1.0. The Company was in compliance with all financial covenants under the credit facility as of ~~June~~September 30, 2019 and through the filing of this report.

Any borrowings under the credit facility are collateralized by substantially all of the assets of the Company and certain of its subsidiaries, including oil and gas properties, personal property and the equity interests of those subsidiaries. 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

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facility. Elevation is a separate 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 of ~~June~~September 30, 2019, ~~$14.4~~$49.9 million of cash was held by Elevation and is earmarked for construction of pipeline infrastructure to serve the development of acreage in its Hawkeye and Southwest Wattenberg areas.

2021 Senior Notes

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

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

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

2024 Senior Notes

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

The Company's 2024 Senior Notes are its senior unsecured obligations and rank equally in right of payment with all of its other senior indebtedness and senior to any of its subordinated indebtedness. The Company's 2024 Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by certain of the Company's current subsidiaries and by certain future restricted subsidiaries that guarantees its indebtedness under a credit facility (the “2024 Senior Note Guarantors”). The 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.

The 2024 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 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.

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2026 Senior Notes

In January 2018, the Company issued at par $750.0 million principal amount of 5.625% Senior Notes due February 1, 2026 (the “2026 Senior Notes” and the offering, 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 used $534.2 million of the net proceeds from the 2026 Senior Notes Offering to fund the tender offer for its 2021 Senior Notes, $52.7 million to redeem any 2021 Senior Notes not tendered and the remainder for general corporate purposes.

The Company's 2026 Senior Notes 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 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 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 2026 Senior Notes (the “2026 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 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 ~~June~~September 30, 2019, the Company had debt issuance costs, net of accumulated amortization, of ~~$3.8~~$3.9 million related to its credit facility which has been reflected on the Company’s condensed consolidated balance sheet within the line item other ~~non‑current~~non-current assets. As of ~~June~~September 30, 2019, the Company had debt issuance costs, net of accumulated amortization, of ~~$15.5~~$15.0 million related to its 2024 and 2026 Senior Notes (collectively, the "Senior Notes") which has been reflected on the Company's balance sheet within the line item Senior Notes, net of unamortized debt issuance costs. Debt issuance costs include origination, legal, engineering and other fees incurred in connection with the Company’s credit facility and Senior Notes. For the three and ~~six~~nine months ended ~~June~~September 30, 2019, the Company recorded amortization expense related to debt issuance costs of ~~$1.3~~$1.0 million and ~~$2.8~~$3.8 million, respectively, as compared to $0.9 million and ~~$11.4~~$12.3 million for the three and ~~six~~nine months ended ~~June~~September 30, 2018, respectively. Debt issuance costs for the ~~six~~nine months ended ~~June~~September 30, 2018 included $9.4 million of acceleration of amortization expense upon the repayment of the Company's 2021 Senior Notes. The repayment of the Company's 2021 Senior Notes had no impact to amortization expense for the three and ~~six~~nine months ended ~~June~~September 30, 2019 and the three months ended ~~June~~September 30, 2018.

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

For the three and ~~six~~nine months ended ~~June~~September 30, 2019, the Company incurred interest expense on ~~long‑term~~long-term debt of ~~$22.2~~$23.8 million and ~~$43.0~~$66.9 million, respectively, as compared to ~~$20.4~~$21.5 million and ~~$40.2~~$61.6 million for the three and ~~six~~nine months ended ~~June~~September 30, 2018, respectively. For the three and ~~six~~nine months ended ~~June~~September 30, 2019, the Company capitalized interest expense on long term debt of ~~$1.8~~$1.6 million and ~~$3.8~~$5.4 million, respectively, as compared to ~~$2.1~~$1.7 million and ~~$4.7~~$6.3 million for the three and ~~six~~nine months ended ~~June~~September 30, 2018, respectively, which has been reflected in the Company’s condensed consolidated financial statements. Also included in interest expense for the ~~six~~nine months ended ~~June~~September 30, 2018 was a make-whole premium of $35.6 million related to the Company's repayment of its 2021 Senior Notes in January and February 2018. The repayment of the Company's 2021 Senior Notes had no impact to interest expense for the three and ~~six~~nine months ended ~~June~~September 30, 2019 and the three months ended ~~June~~September 30, 2018.

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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 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 ~~and six~~ months ended ~~June~~September 30, 2019, the Company did not repurchase 2026 Senior Notes. For the nine months ended September 30, 2019, the Company repurchased ~~2026 Senior Notes with~~ a nominal value of ~~$14.0 million and~~ $49.8 million ~~respectively,~~ for ~~$10.9 million and~~ $39.3 million ~~respectively,~~ in connection with the Senior Notes Repurchase Program. Interest expense for the ~~three and six~~nine months ended ~~June~~September 30, 2019 included ~~$3.1 million and~~a $10.5 million of gain on debt repurchase ~~respectively,~~ related to the Company's Senior Note Repurchase Program. The Senior Note Repurchase Program had no impact to interest expense for three and ~~six~~nine months ended ~~June~~September 30, 2018.

Note 5—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.

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.

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 ~~nine~~10 counterparties. 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 no0 credit ~~risk~~risks 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 ~~June~~September 30, 2019 are summarized below:


	2019		2020		2021		2022		2023
NYMEX WTI Crude Swaps:
Notional volume (Bbl)	3,950,000		3,200,001		3,000,000		1,020,000		900,000
Weighted average fixed price ($/Bbl)	$	57.86	$	59.81	$	57.80	$	54.84	$	54.87
NYMEX WTI Crude Purchased Puts:
Notional volume (Bbl)	200,000		9,725,001		1,800,000		—		—
Weighted average purchased put price ($/Bbl)	$	60.00	$	54.99	$	55.02	$	—	$	—



NYMEX WTI Crude Sold Calls:
Notional volume (Bbl)	200,000		9,725,001		1,800,000		—		—
Weighted average sold call price ($/Bbl)	$	64.00	$	62.04	$	63.70	$	—	$	—
NYMEX WTI Crude Sold Puts:
Notional volume (Bbl)	1,000,000		12,250,002		4,200,000		600,000		600,000
Weighted average sold put price ($/Bbl)	$	44.60	$	42.91	$	43.50	$	43.00	$	43.00
NYMEX HH Natural Gas Swaps:
Notional volume (MMBtu)	9,000,000		35,400,000		—		—		—
Weighted average fixed price ($/MMBtu)	$	2.75	$	2.75	$	—	$	—	$	—
NYMEX HH Natural Gas Purchased Puts:
Notional volume (MMBtu)	—		600,000		—		—		—
Weighted average purchased put price ($/MMBtu)	$	—	$	2.90	$	—	$	—	$	—
NYMEX HH Natural Gas Sold Calls:
Notional volume (MMBtu)	—		600,000		—		—		—
Weighted average sold call price ($/MMBtu)	$	—	$	3.48	$	—	$	—	$	—



CIG Basis Gas Swaps:
Notional volume (MMBtu)	11,100,000		43,200,000		—		—		—
Weighted average fixed basis price ($/MMBtu)	$	(0.72)	$	(0.61)	$	—	$	—	$	—

2019 2020 2021
NYMEX WTI Crude Swaps:
Notional volume (Bbl) 4,400,000
4,400,000
1,800,000
Weighted average fixed price ($/Bbl) $ 56.65
$ 60.09
$ 59.80
NYMEX WTI Crude Purchased Puts:
Notional volume (Bbl) 3,200,000
11,025,000
1,800,000
Weighted average purchased put price ($/Bbl) $ 55.31
$ 54.99
$ 55.02
NYMEX WTI Crude Sold Calls:
Notional volume (Bbl) 2,600,000
11,025,000
1,800,000
Weighted average sold call price ($/Bbl) $ 64.17
$ 62.40
$ 63.70
NYMEX WTI Crude Sold Puts:
Notional volume (Bbl) 3,000,000
15,000,000
3,600,000
Weighted average sold put price ($/Bbl) $ 43.93
$ 42.79
$ 43.58
NYMEX HH Natural Gas Swaps:
Notional volume (MMBtu) 18,000,000
35,400,000
—
Weighted average fixed price ($/MMBtu) $ 2.75
$ 2.75
$ —
NYMEX HH Natural Gas Purchased Puts:
Notional volume (MMBtu) —
600,000
—
Weighted average purchased put price ($/MMBtu) $ —
$ 2.90
$ —
NYMEX HH Natural Gas Sold Calls:
Notional volume (MMBtu) —
600,000
—
Weighted average sold call price ($/MMBtu) $ —
$ 3.48
$ —
CIG Basis Gas Swaps:
Notional volume (MMBtu) 22,200,000
43,200,000
$ —
Weighted average fixed basis price ($/MMBtu) $ (0.72 ) $ (0.61 ) —

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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 September 30, 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 ⁽⁴⁾	$	114,221	$	(47,741)	$	66,480	$	(83)	$	107,917
Non-current assets	$	77,188	$	(35,668)	$	41,520	$	—	$	—
Current liabilities ⁽⁴⁾	$	(47,849)	$	47,741	$	(108)	$	83	$	(108)
Non-current liabilities	$	(35,751)	$	35,668	$	(83)	$	—	$	—

As of June 30, 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 ⁽⁴⁾
$ 69,736
$ (57,777 ) $ 11,959
$ (2,315 ) $ 37,315
Non-current assets $ 75,818
$ (48,147 ) $ 27,671
$ —
$ —
Current liabilities ⁽⁴⁾
$ (61,318 ) $ 57,777
$ (3,541 ) $ 2,315
$ (1,360 )
Non-current liabilities $ (48,281 ) $ 48,147
$ (134 ) $ —
$ —


	As of December 31, 2018
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 ⁽⁵⁾	$	115,852	$	(66,945)	$	48,907	$	(192)	$	57,147
Non-current assets	$	17,217	$	(8,785)	$	8,432	$	—	$	—
Current liabilities ⁽⁵⁾	$	(67,141)	$	66,945	$	(196)	$	192	$	(4)
Non-current liabilities	$	(8,785)	$	8,785	$	—	$	—	$	—

As of December 31, 2018
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 ⁽⁵⁾
$ 115,852
$ (66,945 ) $ 48,907
$ (192 ) $ 57,147
Non-current assets $ 17,217
$ (8,785 ) $ 8,432
$ —
$ —
Current liabilities ⁽⁵⁾
$ (67,141 ) $ 66,945
$ (196 ) $ 192
$ (4 )
Non-current liabilities $ (8,785 ) $ 8,785
$ —
$ —
$ —


~~(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.


~~(4)~~	Gross current liabilities include a deferred premium liability of $3.0 million related to the Company's deferred premiums. Gross current assets include a deferred premium asset of $0.8 million related to the Company's deferred premiums.


~~(5)~~	Gross current liabilities include a deferred premium liability of $7.7 million related to the Company's deferred put premiums. Gross current assets include a deferred premium asset of $0.8 million related to the Company's deferred put premiums.

(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.

(4)Gross current liabilities include a deferred premium liability of $1.7 million related to the Company's deferred premiums. Gross current assets include a deferred premium asset of $0.4 million related to the Company's deferred premiums.

(5)Gross current liabilities include a deferred premium liability of $7.7 million related to the Company's deferred put premiums. Gross current assets include a deferred premium asset of $0.8 million related to the Company's deferred put premiums.

The table below sets forth the commodity derivatives gain (loss) for the three and ~~six~~nine months ended ~~June~~September 30, 2019 and 2018 (in thousands). Commodity derivatives gain (loss) is included under the other income (expense) line item in the condensed consolidated statements of operations.


	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2019		2018		2019		2018
Commodity derivatives gain (loss)	$	87,956	$	(35,913)	$	39,383	$	(175,752)

For the Three Months Ended June 30, For the Six Months Ended June 30,
2019 2018 2019 2018
Commodity derivatives gain (loss) $ 73,519
$ (89,511 ) $ (48,572 ) $ (139,839 )

Note 6—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~~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,

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inflation rates and estimated dates of abandonment. The asset retirement liability is accreted to its present value each period and the capitalized asset retirement costs are depleted with proved oil and gas properties using the unit of production method.

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


	For the Nine Months Ended September 30, 2019
Balance beginning of period	$	69,791
Liabilities incurred or acquired	315
Liabilities settled	(15,484)
Revisions in estimated cash flows	35,466
Accretion expense	3,838
Balance end of period	$	93,926

For the Six Months Ended June 30, 2019
Balance beginning of period $ 69,791
Liabilities incurred or acquired 244
Liabilities settled (9,438 )
Revisions in estimated cash flows 26,596
Accretion expense 2,307
Balance end of period $ 89,500

For the Six Months Ended June 30, 2018
Exploration and Production Gathering and Facilities Elimination of Intersegment Transactions Consolidated Total
Revenues:
Revenues from external customers $ 490,411
$ —
$ —
$ 490,411
Intersegment revenues —
—
—
—
Total Revenues $ 490,411
$ —
$ —
$ 490,411

Operating Expenses and Other Income (Expense):
Depletion, depreciation, amortization and accretion $ (202,981 ) $ —
$ —
$ (202,981 )
Interest income 145
—
—
145
Interest expense (82,504 ) —
—
(82,504 )
Earnings in unconsolidated subsidiaries —
1,043
—
1,043
Subtotal Operating Expenses and Other Income (Expense): $ (285,340 ) $ 1,043
$ —
$ (284,297 )

Segment Assets $ 3,788,624
$ 35,436
$ —
$ 3,824,060
Capital Expenditures $ 528,067
$ 20,178
$ —
$ 548,245
Investment in Equity Method Investees $ —
$ 9,019
$ —
$ 9,019
Segment EBITDAX $ 293,072
$ 1,043
$ —
$ 294,115

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The following table presents a reconciliation of Adjusted EBITDAX by segment to the GAAP financial measure of income (loss) before income taxes for the three and ~~six~~nine months ended ~~June~~September 30, 2019 and 2018 (in thousands).

For the Three Months Ended For the Six Months Ended
June 30, 2019 June 30, 2018 June 30, 2019 June 30, 2018
Reconciliation of Adjusted EBITDAX to Income (Loss) Before Income Taxes
Exploration and production segment EBITDAX $ 129,534
$ 152,439
$ 268,045
$ 293,072
Gathering and facilities segment EBITDAX (223 ) 704
(547 ) 1,043
Subtotal of Reportable Segments $ 129,311
$ 153,143
$ 267,498
$ 294,115
Less:
Depletion, depreciation, amortization and accretion $ (118,368 ) $ (106,774 ) $ (237,138 ) $ (202,981 )
Impairment of long lived assets (2,985 ) (128 ) (11,233 ) (128 )
Exploration expenses (13,287 ) (3,021 ) (19,481 ) (10,288 )
Gain on sale of property and equipment 97
59,902
319
59,902
Gain (loss) on commodity derivatives 73,519
(89,511 ) (48,572 ) (139,839 )
Settlements on commodity derivative instruments 14,203
35,652
24,532
58,905
Premiums paid for derivatives that settled during the period 9,549
730
19,098
3,235
Stock-based compensation expense (14,937 ) (17,743 ) (27,945 ) (33,464 )
Amortization of debt issuance costs (1,328 ) (926 ) (2,826 ) (11,368 )
Make-whole premium on 2021 Senior Notes —
—
—
(35,600 )
Gain on repurchase of 2026 Senior Notes 3,169
—
10,486
—
Interest expense (20,399 ) (18,276 ) (39,226 ) (35,536 )
Income (Loss) Before Income Taxes $ 58,544
$ 13,048
$ (64,488 ) $ (53,047 )


	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2019		2018		2019		2018
	As restated				As restated
Reconciliation of Adjusted EBITDAX to Income Before Income Taxes
Exploration and production segment EBITDAX	$	138,491	$	170,004	$	406,539	$	463,415
Gathering and facilities segment EBITDAX	(622)		(601)		(1,168)		102
Subtotal of Reportable Segments	$	137,869	$	169,403	$	405,371	$	463,517
Less:
Depletion, depreciation, amortization and accretion	$	(114,996)	$	(107,315)	$	(352,134)	$	(310,296)
Impairment of long lived assets	—		(16,166)		(11,233)		(16,294)
Exploration expenses	(13,245)		(11,038)		(32,725)		(21,326)
Gain on sale of property and equipment and assets of unconsolidated subsidiary	1,011		83,559		1,329		143,461
Gain (loss) on commodity derivatives	87,956		(35,913)		39,383		(175,752)
Settlements on commodity derivative instruments	(16,101)		41,009		8,432		99,914
Premiums paid for derivatives that settled during the period	812		1,956		19,910		5,191
Stock-based compensation expense	(11,358)		(17,420)		(39,306)		(50,883)
Amortization of debt issuance costs	(974)		(935)		(3,799)		(12,303)
Make-whole premium on 2021 Senior Notes	—		—		—		(35,600)
Gain on repurchase of 2026 Senior Notes	—		—		10,486		—
Interest expense	(22,250)		(19,790)		(61,478)		(55,326)
Income (Loss) Before Income Taxes	$	48,724	$	87,350	$	(15,764)	$	34,303

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

As discussed in Note 2—Basis of Presentation, Restatement, Significant Accounting Policies and Recent Accounting Pronouncements to the condensed consolidated financial statements, the Company has restated its financial statements as of and for the three and nine months ended September 30, 2019, and the following information reflects the impact of that restatement.

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:

•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;

•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;

•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;

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

•limited control over non-operated properties;

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

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

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

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

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

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

•changes in tax laws;

•effects of competition; and

•seasonal weather conditions.

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

In addition to the other information and risk factors set forth in this Quarterly Report, you should carefully consider the risk factors and other cautionary statements described under the heading “Risk Factors” included in our Annual Report on Form 10-K for the year ended December 31, 2018 (our “Annual Report”) and in our other filings with the Securities Exchange Commission, which could materially affect our business, financial condition or future results. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results. Other than as set forth in this Quarterly Report, there have been no material changes in our risk factors from those described in our Annual Report.

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

Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) is intended to provide the reader of the financial statements with a narrative from the perspective of management on the financial condition, results of operations, liquidity and certain other factors that may affect the Company’s operating results. MD&A should be read in conjunction with the Condensed Consolidated Financial Statements and related Notes included in Part I, Item 1 of this Quarterly Report. The following information updates the discussion of the Company’s financial condition provided in its Annual Report and analyzes the changes in the results of operations between the three and ~~six~~nine months ended ~~June~~September 30, 2019 and 2018.

EXECUTIVE SUMMARY

We are an independent oil and gas company focused on the acquisition, development and production of oil, natural gas and NGL reserves in the Rocky Mountain region, primarily in the Wattenberg Field of the DJ Basin. 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 most productive areas of what we consider to be the core of the DJ Basin. We are focused on growing our proved reserves and production primarily through the development of our large inventory of identified ~~liquids‑rich~~liquids-rich horizontal drilling locations, as well as the design and support of midstream assets to gather and process crude oil and gas production focused in the DJ Basin.

Financial Results

For the three and ~~six~~nine months ended ~~June~~September 30, 2019, crude oil, natural gas and NGL sales, coupled with the impact of settled derivatives, decreased to ~~$198.3~~$192.3 million and ~~$400.3~~$592.6 million, respectively, as compared to ~~$224.4~~$239.2 million and ~~$428.3~~$667.5 million, respectively, in the same prior year periods due to a decrease of ~~$7.23~~$8.34 and ~~$6.12~~$6.89 in realized price per BOE, respectively, including settled derivatives, partially offset by an increase in sales volumes of ~~846~~427 MBoe and ~~1,883~~2,312 MBoe, respectively.

For the three and ~~six~~nine months ended ~~June~~September 30, 2019, we had net income of ~~$43.4~~$33.9 million and net loss of ~~$50.6~~$16.7 million, respectively, as compared to net income of ~~$8.8~~$65.2 million and ~~net loss of $43.1~~$22.0 million for the three and ~~six~~nine months ended ~~June~~September 30, 2018, respectively. The change toin net income for the three months ended ~~June~~September 30, 2019 from the three months ended ~~June~~September 30, 2018 was primarily driven by a decrease in sales revenue of $105.2 million partially offset by an increase in commodity derivative gain of ~~$163.0 million, partially offset by a decrease in sales revenues of $38.1~~$123.9 million and an increase in operating expenses of ~~$20.2~~$28.3 million excluding the gain on sale of property and equipment and assets of ~~$59.8~~unconsolidated subsidiary of $82.5 million. The change to net loss for the ~~six~~

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nine months ended ~~June~~September 30, 2019 from net income for the ~~six~~nine months ended ~~June~~September 30, 2018 was primarily driven by a decrease in sales revenues of ~~$46.4 million, an~~ ~~increase~~ ~~in operating expenses of $107.9 million, a decrease in commodity derivative loss of $91.3~~$151.6 million and a decrease in interest expense of ~~$50.9~~$48.4 million related to redemption of the Company's 2021 Senior Notes during the ~~six~~nine months ended ~~June~~September 30, ~~2018.~~2018 partially offset by an increase in operating expenses of $162.2 million and an increase in the commodity derivative gain of $215.1 million.

Adjusted EBITDAX was ~~$129.3~~$137.9 million and ~~$267.5~~$405.4 million for the three and ~~six~~nine months ended ~~June~~September 30, 2019, respectively, as compared to ~~$153.1~~$169.4 million and ~~$294.1~~$463.5 million for the three and ~~six~~nine months ended ~~June~~September 30, 2018, respectively, reflecting a ~~15.6% decrease~~18.6% and ~~a 9.0%~~an 12.5% decrease, respectively. 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 ~~June~~September 30, 2019, our aggregate drilling, completion, and leasehold capital expenditures, totaled ~~$222.8~~$135.0 million, of which ~~$210.2~~$122.3 million was drilling and completion additions and ~~$12.6~~$12.7 million was leasehold and surface acreage additions. This excludes the impact of the decrease in outstanding elections of ~~$12.7~~$3.9 million. In addition, Elevation Midstream, LLC, our wholly owned midstream subsidiary, incurred ~~$68.6~~$65.1 million of capital expenditures during the three months ended ~~June~~September 30, 2019. These capital expenditures are funded entirely pursuant to the Elevation Midstream, LLC Securities Purchase Agreement.

During the three months ended ~~June~~September 30, 2019, we drilled 3327 gross ~~(27~~(20.0 net) wells with an average length of approximately ~~9,400~~10,900 feet and completed 3637 gross ~~(31~~(31.2 net) wells with an average lateral length of approximately ~~10,100~~8,900 feet. We turned to sales 3622 gross ~~(32~~(17.7 net) wells with an average lateral length of approximately ~~6,800~~9,500 feet.

Recent Developments

~~Elevation Preferred Units~~

On July 10, 2019, Elevation closed on an additional 100,000 Preferred Units under the existing securities purchase agreement with a third party, pursuant to which Elevation agreed to sell an additional 100,000 Preferred Units of Elevation at a price of $990 per Elevation Preferred Unit with an aggregate liquidation preference of $100.0 million resulting in net proceeds of approximately $99.0 million. These Preferred Units are non-recourse to Extraction.

~~June 2019 Credit Facility Amendment~~

On June 26, 2019, we amended our revolving credit facility to (i) increase the elected commitments from $650.0 million to $900.0 million, (ii) increase the amount for permitted letters of credit from $50.0 million to $100.0 million and increase the letter of credit sublimit for the Company's oil marketer from $35.0 million to $40.0 million, (iii) decrease the borrowing base from $1.2 billion to $1.1 billion and (iv) increase the limitation on permitted investments from $15.0 million to $20.0 million.

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

On April 16, 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. 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 Colorado Oil and Gas Conservation Commission, (ii) directs the Colorado Air Quality Control Commission 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 and (v) repeals an exemption for oil and gas production from counties’ authority to regulate noise. Although industry trade associations opposed SB181, management believes that Extraction can continue to successfully operate our business. However, the enactment of SB181 could lead to delays and additional costs to our business.

Aurora and Commerce City Operator Agreements

Extraction entered into operator agreements with the city of Aurora and Commerce City on July 8, 2019 and September 18, 2019, respectively. The agreements established a framework for the permitting process and Extraction’s Best Management Practices while operating within the cities, including electric drilling rigs and quiet hydraulic fracturing fleets. They also identified the wells to be drilled through year-end 2025 and 2024, respectively.

Rocky Mountain Midstream East Greeley Pipeline and Auburn Compressor

On October 14, 2019, Rocky Mountain Midstream commenced service on its East Greeley Pipeline and Auburn Compressor Station. This pipeline and compressor station enables us to flow our oil and gas from parts of our East Greeley area without the bottlenecks or constraints we have historically experienced in this area.

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Badger Central Gathering Facility

On October 3, 2019, Elevation commenced moving crude oil, natural gas and water through its Badger central gathering facility, which enables Extraction to efficiently transport its crude oil and natural gas production along with water used during the completion process. The use of this gathering facility allows for the elimination of oil or water storage on the well pad site and reduces truck traffic, which minimizes the impact to the surrounding environment and communities.

Western Gas Outage

During portions of August and September 2019, Extraction’s production on Western Gas' gathering system was significantly curtailed due to an unplanned outage at their Lancaster gas plant. We estimate our third quarter production was negatively impacted by this outage by approximately 8,304 BOE/d. This plant resumed normal operations in October 2019.

November 2019 Credit Facility Amendment

On November 4, 2019, we amended our revolving credit facility to decrease the borrowing base from $1.1 billion to $950.0 million, associated with the scheduled borrowing base redetermination. The current elected commitments were also decreased to $950.0 million.

August 2019 Divestiture

On August 22, 2019, we 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. We continue to explore divestitures, as part of our ongoing initiative to divest of non-strategic assets.

August 2019 Credit Facility Amendment

In August 2019, we amended its revolving credit facility to increase the elected commitments from $900.0 million to $1.0 billion.

Elevation Preferred Units

On July 10, 2019, Elevation closed on an additional 100,000 Elevation Preferred Units under an existing securities purchase agreement with a third party, pursuant to which Elevation had agreed to sell an additional 100,000 Elevation Preferred Units at a price of $990 per Elevation Preferred Unit with an aggregate liquidation preference of $100.0 million, and resulting in net proceeds of approximately $96.5 million, after deducting discounts and related offering expenses. These Elevation Preferred Units are non-recourse to Extraction.

June 2019 Credit Facility Amendment

Senior Notes Repurchase Program

On January 4, 2019, our Board of Directors authorized a program, subject to the amendment to our revolving credit facility, to repurchase up to $100.0 million of our Senior Notes (“Senior Notes Repurchase Program”). Our Senior Notes Repurchase Program is subject to restrictions under our Credit Facility and does not obligate us to acquire any specific nominal amount of Senior Notes. ~~For~~During the ~~six~~nine months ended ~~June~~September 30, 2019, we repurchased ~~2026 Senior Notes with~~ a nominal value of $49.8 million for $39.3 million in connection with the Senior Notes Repurchase Program.

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Stock Repurchase Program

On November 19, 2018, we announced the Board of Directors had authorized a program to repurchase up to $100.0 million of our common stock ("Stock Repurchase Program"). On April 1, 2019, wethe Company announced the Board of Directors had authorized an extension and increase in our ongoing Stock Repurchase Program bringing the total amount authorized to $163.2 million ("Extended Stock Repurchase Program"). ~~We have~~Prior to commencing the Extended Stock Repurchase Program, the Company had purchased approximately 13.0 million shares of its common stock for $63.2 million under the Stock Repurchase Program, ~~prior~~which repurchases were completed in the third quarter of 2019, bringing the total amount of common stock repurchased to $163.2 million and completing the Extended Stock Repurchase Program. We are authorized to repurchase an incremental $100.0 million in common stock from the date of the Extended Stock Repurchase Program, bringing the total amount authorized to be repurchased to approximately $163.2 million. Our Stock Repurchase Program does not obligate us to acquire any specific number of shares and will expire on December 31, 2019. We intend to conduct any open market stock repurchase activities in compliance with the safe harbor provisions of Rule 10b-18 of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). During the ~~six~~three and nine months ended ~~June~~September 30, 2019, ~~we repurchased approximately 29.4 million shares of our common stock for $115.7 million. Subsequent to June 30, 2019 through~~ the ~~date of this filing, we~~Company repurchased approximately 4.8 million ~~additional~~and 34.1 million shares of ~~our~~its common stock for $21.2 ~~million.~~million and $136.9 million, respectively.

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).

Sources of Revenues

Our revenues are derived from the sale of our oil and natural gas production, as well as the sale of NGL 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 ~~June~~September 30, 2019, our revenues were derived ~~83%~~85% from oil sales, 10% from natural gas sales and 5% from NGL sales. For the three months ended September 30, 2018, our revenues were derived 80% from oil sales, 8% from natural gas sales and 12% from NGL sales. For the nine months ended September 30, 2019, our revenues were derived 81% from oil sales, 12% from natural gas sales and 7% from NGL sales. For the ~~three~~nine months ended June 30, 2018, our revenues were derived 82% from oil sales, 8% from natural gas sales and 10% from NGL sales. For the six months ended June 30, 2019, our revenues were derived 79% from oil sales, 13% from natural gas sales and 8% from NGL sales. For the six months ended JuneSeptember 30, 2018, our revenues were derived 80% from oil sales, 9% from natural gas sales and 11% 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.

Sales Volumes

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


	For the Three Months Ended			For the Nine Months Ended
	September 30,			September 30,
	2019	2018	2019	2018
Oil (MBbl)	3,597	3,618	10,830	10,394
Natural gas (MMcf)	14,418	11,838	43,433	33,612
NGL (MBbl)	1,390	1,372	4,097	3,860
Total (MBoe)	7,390	6,963	22,167	19,855
Average net sales (BOE/d)	80,327	75,680	81,198	72,731

For the Three Months Ended For the Six Months Ended
June 30, June 30,
2019 2018 2019 2018
Oil (MBbl) 3,650
3,531
7,233
6,776
Natural gas (MMcf) 15,055
11,370
29,015
21,774
NGL (MBbl) 1,380
1,268
2,707
2,488
Total (MBoe) 7,540
6,694
14,776
12,893
Average net sales (BOE/d) 82,856
73,563
81,635
71,231

As reservoir pressures decline, production from a given well or formation decreases. Growth in our future production and reserves will depend on our ability to continue to add or develop proved reserves in excess of our production. 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

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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 ~~June~~September 30, 2019, NYMEX West Texas Intermediate oil prices ranged from a high of $107.26 per Bbl to a low of $26.21 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 per MMBtu during the same period. Declines in, and continued depression of, the price of oil and natural gas occurring during 2015 also during 2018 and 2019 are due to a combination of factors including increased U.S. supply, global economic concerns and geopolitical risks. These price variations can have a material impact on our financial results and capital expenditures.

Oil pricing is predominately 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.

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.

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	For the Three Months Ended						For the Six Months Ended							For the Three Months Ended									For the Nine Months Ended
	June 30,						June 30,							September 30,									September 30,
	2019			2018			2019			2018				2019			2018			2019			2018
Oil													Oil	As restated						As restated
NYMEX WTI High ($/Bbl)	$	66.30		$	74.15		$	66.30		$	74.15		NYMEX WTI High ($/Bbl)	$	62.90		$	74.14		$	66.30		$	74.15
NYMEX WTI Low ($/Bbl)	$	51.14		$	62.06		$	46.54		$	59.19		NYMEX WTI Low ($/Bbl)	$	51.09		$	65.01		$	46.54		$	59.19
NYMEX WTI Average ($/Bbl)	$	59.91		$	67.91		$	57.45		$	65.46		NYMEX WTI Average ($/Bbl)	$	56.44		$	69.43		$	57.10		$	66.79
Average Realized Price ($/Bbl)	$	50.72		$	60.46		$	48.46		$	58.11		Average Realized Price ($/Bbl)	$	41.99		$	62.32		$	46.31		$	59.58
Average Realized Price, with derivative settlements ($/Bbl)	$	43.83		$	48.89		$	42.87		$	47.28		Average Realized Price, with derivative settlements ($/Bbl)	$	45.58		$	50.02		$	43.77		$	48.23
Average Realized Price as a % of Average NYMEX WTI	84.7		%	89.0		%	84.4		%	88.8		%	Average Realized Price as a % of Average NYMEX WTI	74.4		%	89.8		%	81.1		%	89.2		%
Differential ($/Bbl) to Average NYMEX WTI	$	(9.19	)	$	(7.45	)	$	(8.99	)	$	(7.35	)
Differential ($/Bbl) to Average NYMEX WTI ⁽¹⁾													Differential ($/Bbl) to Average NYMEX WTI ⁽¹⁾	$	(8.28)		$	(7.11)		$	(8.74)		$	(7.21)
Natural Gas													Natural Gas
NYMEX Henry Hub High ($/MMBtu)	$	2.71		$	3.02		$	3.59		$	3.63		NYMEX Henry Hub High ($/MMBtu)	$	2.68		$	3.08		$	3.59		$	3.63
NYMEX Henry Hub Low ($/MMBtu)	$	2.19		$	2.66		$	2.19		$	2.55		NYMEX Henry Hub Low ($/MMBtu)	$	2.07		$	2.72		$	2.07		$	2.55
NYMEX Henry Hub Average ($/MMBtu)	$	2.51		$	2.83		$	2.69		$	2.84		NYMEX Henry Hub Average ($/MMBtu)	$	2.33		$	2.86		$	2.56		$	2.85
NYMEX Henry Hub Average converted to a $/Mcf basis (factor of 1.1 to 1)	$	2.76		$	3.11		$	2.96		$	3.12		NYMEX Henry Hub Average converted to a $/Mcf basis (factor of 1.1 to 1)	$	2.56		$	3.15		$	2.82		$	3.14
Average Realized Price ($/Mcf)	$	1.44		$	1.74		$	1.98		$	2.02		Average Realized Price ($/Mcf)	$	1.17		$	1.95		$	1.71		$	1.99
Average Realized Price, with derivative settlements ($/Mcf)	$	1.53		$	2.19		$	1.88		$	2.53		Average Realized Price, with derivative settlements ($/Mcf)	$	1.33		$	2.08		$	1.69		$	2.37
Average Realized Price as a % of Average NYMEX Henry Hub⁽¹⁾	52.2		%	55.9		%	66.9		%	64.7		%
Average Realized Price as a % of Average NYMEX Henry Hub													Average Realized Price as a % of Average NYMEX Henry Hub	45.7		%	61.9		%	60.6		%	63.4		%
Differential ($/Mcf) to Average NYMEX Henry Hub	$	(1.32	)	$	(1.37	)	$	(0.98	)	$	(1.10	)	Differential ($/Mcf) to Average NYMEX Henry Hub	$	(1.39)		$	(1.20)		$	(1.11)		$	(1.15)
NGL													NGL
Average Realized Price ($/Bbl)	$	11.04		$	21.22		$	13.24		$	21.21		Average Realized Price ($/Bbl)	$	6.55		$	24.49		$	10.97		$	22.38
Average Realized Price as a % of Average NYMEX WTI	18.4		%	31.2		%	23.0		%	32.4		%	Average Realized Price as a % of Average NYMEX WTI	11.6		%	35.3		%	19.2		%	33.5		%
BOE													BOE
Average Realized Price per BOE	$	29.45		$	38.87		$	30.05		$	38.04		Average Realized Price per BOE	$	23.94		$	40.53		$	28.01		$	38.91
Average Realized Price per BOE with derivative settlements	$	26.30		$	33.53		$	27.09		$	33.22		Average Realized Price per BOE with derivative settlements	$	26.01		$	34.35		$	26.73		$	33.62

For the Six Months Ended
June 30,
2019 2018
NYMEX WTI Crude Swaps:
Notional volume (Bbl) 3,000,000
3,000,000
Weighted average fixed price ($/Bbl) $ 54.64
$ 50.70
NYMEX WTI Crude Purchased Puts:
Notional volume (Bbl) 9,850,000
7,827,000
Weighted average purchased put price ($/Bbl) $ 46.21
$ 41.94
NYMEX WTI Crude Purchased Calls:
Notional volume (Bbl) 10,500,000
570,000
Weighted average purchased call price ($/Bbl) $ 63.59
$ 60.69
NYMEX WTI Crude Sold Calls:
Notional volume (Bbl) 13,400,000
3,370,000
Weighted average sold call price ($/Bbl) $ 62.24
$ 56.17
NYMEX WTI Crude Sold Puts:
Notional volume (Bbl) 8,700,000
6,838,000
Weighted average sold put price ($/Bbl) $ 43.58
$ 38.22
NYMEX HH Natural Gas Swaps:
Notional volume (MMBtu) 14,400,000
21,000,000
Weighted average fixed price ($/MMBtu) $ 2.88
$ 3.16
NYMEX HH Natural Gas Purchased Puts:
Notional volume (MMBtu) 3,600,000
1,200,000
Weighted average purchased put price ($/MMBtu) $ 3.04
$ 3.00
NYMEX HH Natural Gas Sold Calls:
Notional volume (MMBtu) 3,600,000
1,200,000
Weighted average sold call price ($/MMBtu) $ 3.46
$ 3.15
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) 20,000,000
16,475,000
Weighted average fixed basis price ($/MMBtu) $ (0.74 ) $ (0.53 )
Total Amounts Received/(Paid) from Settlement (in thousands) $ (24,532 ) $ (58,905 )
Cash provided by changes in Accounts Receivable and Accounts Payable related to Commodity Derivatives $ 2,614
$ 4,626
Cash Settlements on Commodity Derivatives per Consolidated Statements of Cash Flows $ (21,918 ) $ (54,279 )

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Lease Operating Expenses

All direct and allocated indirect costs of lifting hydrocarbons from a producing formation to the surface constitutes part of the current operating expenses of a working interest. Such costs include labor, superintendence, supplies, repairs, maintenance, water injection and disposal costs, allocated overhead charges, workover, insurance and other expenses incidental to production, but exclude lease acquisition or drilling or completion expenses. ~~We are seeing increases in costs associated with equipment rental and services, related to the increase in commodity pricing during 2018 and through the first half of 2019.~~

Capital Expenditures

For the ~~six~~nine months ended ~~June~~September 30, 2019, we incurred approximately ~~$349.7~~$472.0 million in drilling and completion capital expenditures, excluding the impact of a decrease in outstanding elections of ~~$4.4~~$7.9 million. For the ~~six~~nine months ended ~~June~~September 30, 2019, we drilled 6391 gross ~~(53~~(74.6 net) wells with an average lateral length of approximately ~~8,200~~9,100 feet and completed 76113 gross ~~(66~~(98.2 net) wells with an average lateral length of approximately ~~8,600~~8,700 feet. We turned to sales 4365 gross ~~(38~~(56.7 net) wells with an average lateral length of approximately ~~7,300~~8,000 feet. In addition, we incurred approximately ~~$31.7~~$44.5 million of leasehold and surface acreage additions, excluding the impact of the increase in outstanding elections of ~~$3.4~~$3.0 million. In addition, Elevation Midstream, LLC, our wholly owned midstream subsidiary, incurred ~~$127.5~~$192.6 million of capital expenditures during the ~~six~~nine months ended ~~June~~September 30, 2019. These capital expenditures are funded entirely pursuant to the Elevation Midstream, LLC Securities Purchase Agreement.

~~Our~~In October 2019, we revised our 2019 capital budget for the drilling and completion of operated and non-operated wells ~~is approximately~~from a range of $585.0 million to $675.0 million ~~substantially all of which we~~to approximately $520.0 million to $550.0 million. We intend to allocate substantially all our capital budget to the Core DJ Basin. We ~~expect~~expected to drill 125 gross operated wells, complete 122 gross operated wells and turn-in-line 111 gross operated wells. As a result of the change in our capital budget, we expect to drill 108 gross operated wells, complete 118 gross operated wells and turn-in-line 113 gross operated wells. Our capital budget still anticipates a one to two operated rig drilling program and excludes up to $250.0 million for Elevation, which is fully funded by a third party and any amounts that 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”). 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 accretion (“DD&A”), impairment of long lived assets, exploration expenses, ~~(gain) loss~~gain on sale of property and equipment and assets of unconsolidated subsidiary, (gain) loss on commodity derivatives, settlements on commodity derivative instruments, premiums paid for derivatives that settled during the period, stock-based compensation expense, amortization of debt issuance costs, make-whole premiums, gain on repurchase of notes, interest expense, income tax expense (benefit) and non-recurring charges. Adjusted EBITDAX is also used to evaluate the performance of reportable segments. See Note 13 - Segment Information in Item 8 in 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

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a widely followed measure of operating performance. Additionally, our management team believes Adjusted EBITDAX is useful to an investor in evaluating our financial performance because this measure (i) is widely used by investors in the oil and natural gas industry to measure a company’s operating performance without regard to items excluded from the calculation of such term, among other factors; (ii) helps investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital structure from our operating structure; and (iii) is used by our management team for various purposes, including as a measure of operating performance, in presentations to our board of directors, as a basis for strategic planning and forecasting.

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


	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2019		2018		2019		2018
	As restated				As restated
Reconciliation of Net Income (Loss) to Adjusted EBITDAX:
Net income (loss)	$	33,924	$	65,150	$	(16,664)	$	22,003
Add back:
Depletion, depreciation, amortization and accretion	114,996		107,315		352,134		310,296
Impairment of long lived assets	—		16,166		11,233		16,294
Exploration expenses	13,245		11,038		32,725		21,326
Gain on sale of property and equipment and assets of unconsolidated subsidiary	(1,011)		(83,559)		(1,329)		(143,461)
(Gain) loss on commodity derivatives	(87,956)		35,913		(39,383)		175,752
Settlements on commodity derivative instruments	16,101		(41,009)		(8,432)		(99,914)
Premiums paid for derivatives that settled during the period	(812)		(1,956)		(19,910)		(5,191)
Stock-based compensation expense	11,358		17,420		39,306		50,883
Amortization of debt issuance costs	974		935		3,799		12,303
Make-whole premium on 2021 Senior Notes	—		—		—		35,600
Gain on repurchase of 2026 Senior Notes	—		—		(10,486)		—
Interest expense	22,250		19,790		61,478		55,326
Income tax expense	14,800		22,200		900		12,300
Adjusted EBITDAX	$	137,869	$	169,403	$	405,371	$	463,517

For the Three Months Ended
June 30, For the Six Months Ended
June 30,
2019 2018 2019 2018
Reconciliation of Net Income (Loss) to Adjusted EBITDAX:
Net income (loss) $ 43,444
$ 8,848
$ (50,588 ) $ (43,147 )
Add back:
Depletion, depreciation, amortization and accretion 118,368
106,774
237,138
202,981
Impairment of long lived assets 2,985
128
11,233
128
Exploration expenses 13,287
3,021
19,481
10,288
Gain on sale of property and equipment (97 ) (59,902 ) (319 ) (59,902 )
(Gain) loss on commodity derivatives (73,519 ) 89,511
48,572
139,839
Settlements on commodity derivative instruments (14,203 ) (35,652 ) (24,532 ) (58,905 )
Premiums paid for derivatives that settled during the period (9,549 ) (730 ) (19,098 ) (3,235 )
Stock-based compensation expense 14,937
17,743
27,945
33,464
Amortization of debt issuance costs 1,328
926
2,826
11,368
Make-whole premium on 2021 Senior Notes —
—
—
35,600
Gain on repurchase of 2026 Senior Notes (3,169 ) —
(10,486 ) —
Interest expense 20,399
18,276
39,226
35,536
Income tax expense (benefit) 15,100
4,200
(13,900 ) (9,900 )
Adjusted EBITDAX $ 129,311
$ 153,143
$ 267,498
$ 294,115

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:

•

~~On January 1, 2019, we adopted ASC 842 -~~ ~~Leases~~. We adopted using the modified retrospective transition approach to apply the new standard to all leases entered into on or after January 1, 2019 and all existing leases. ASC 842 supersedes previous lease recognition requirements in ASC 840 and resulted in the recognition of $23.0 million of right-of-use assets and $28.7 million of lease liabilities on the condensed consolidated balance sheet as of June

•On January 1, 2019, we adopted ASC 842 - Leases. We adopted using the modified retrospective transition approach to apply the new standard to all leases entered into on or after January 1, 2019 and all existing leases. ASC 842 supersedes previous lease recognition requirements in ASC 840 and resulted in the recognition of $20.5 million of right-of-use assets and $26.1 million of lease liabilities on the condensed consolidated balance sheet as of September 30, 2019. See "Part I, Item 1, Note 2—Basis of Presentation, Restatement, Significant Accounting Policies and Recent Accounting Pronouncements—Leases" for additional information.

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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 components of our revenues, operating expenses, other income (expense) and net income (loss) for the periods indicated (in thousands):


	For the Three Months Ended						For the Nine Months Ended
	September 30,						September 30,
	2019		2018		2019		2018
	(Unaudited)
	As restated				As restated
Revenues:
Oil sales	$	151,042	$	225,467	$	501,591	$	619,211
Natural gas sales	16,801		23,103		74,385		66,991
NGL sales	9,099		33,590		44,940		86,369
Total Revenues	176,942		282,160		620,916		772,571
Operating Expenses:
Lease operating expenses	22,979		20,283		68,445		61,760
Transportation and gathering	6,922		11,786		29,142		29,284
Production taxes	9,711		21,605		46,419		66,317
Exploration expenses	13,245		11,038		32,725		21,326
Depletion, depreciation, amortization and accretion	114,996		107,315		352,134		310,296
Impairment of long lived assets	—		16,166		11,233		16,294
Gain on sale of property and equipment and assets of unconsolidated subsidiary	(1,011)		(83,559)		(1,329)		(143,461)
General and administrative expenses	27,445		35,365		85,835		100,565
Total Operating Expenses	194,287		139,999		624,604		462,381
Operating Income (Loss)	(17,345)		142,161		(3,688)		310,190
Other Income (Expense):
Commodity derivatives gain (loss)	87,956		(35,913)		39,383		(175,752)
Interest expense	(23,224)		(20,725)		(54,791)		(103,229)
Other income	1,337		1,827		3,332		3,094
Total Other Income (Expense)	66,069		(54,811)		(12,076)		(275,887)
Income (Loss) Before Income Taxes	48,724		87,350		(15,764)		34,303
Income tax expense	(14,800)		(22,200)		(900)		(12,300)
Net Income (Loss)	$	33,924	$	65,150	$	(16,664)	$	22,003

For the Three Months Ended For the Six Months Ended
June 30, June 30,
2019 2018 2019 2018
(Unaudited)
Revenues:
Oil sales $ 185,125
$ 213,481
$ 350,549
$ 393,744
Natural gas sales 21,692
19,807
57,584
43,888
NGL sales 15,240
26,908
35,841
52,779
Total Revenues 222,057
260,196
443,974
490,411
Operating Expenses:
Lease operating expenses 23,608
20,774
45,465
41,477
Transportation and gathering 11,854
9,959
22,219
17,498
Production taxes 18,580
24,389
36,709
44,712
Exploration expenses 13,287
3,021
19,481
10,288
Depletion, depreciation, amortization and accretion 118,368
106,774
237,138
202,981
Impairment of long lived assets 2,985
128
11,233
128
Gain on sale of property and equipment (97 ) (59,902 ) (319 ) (59,902 )
General and administrative expenses 30,740
34,231
58,392
65,200
Total Operating Expenses 219,325
139,374
430,318
322,382
Operating Income 2,732
120,822
13,656
168,029
Other Income (Expense):
Commodity derivatives gain (loss) 73,519
(89,511 ) (48,572 ) (139,839 )
Interest expense (18,558 ) (19,202 ) (31,566 ) (82,504 )
Other income 851
939
1,994
1,267
Total Other Income (Expense) 55,812
(107,774 ) (78,144 ) (221,076 )
Income (Loss) Before Income Taxes 58,544
13,048
(64,488 ) (53,047 )
Income tax (expense) benefit (15,100 ) (4,200 ) 13,900
9,900
Net Income (Loss) $ 43,444
$ 8,848
$ (50,588 ) $ (43,147 )

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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						For the Nine Months Ended
	September 30,						September 30,
	2019		2018		2019		2018
	As restated				As restated
Sales (MBoe):	7,390		6,963		22,167		19,855
Oil sales (MBbl)	3,597		3,618		10,830		10,394
Natural gas sales (MMcf)	14,418		11,838		43,433		33,612
NGL sales (MBbl)	1,390		1,372		4,097		3,860
Sales (BOE/d):	80,327		75,680		81,198		72,731
Oil sales (Bbl/d)	39,098		39,323		39,670		38,072
Natural gas sales (Mcf/d)	156,717		128,679		159,095		123,122
NGL sales (Bbl/d)	15,109		14,910		15,007		14,138
Average sales prices⁽¹⁾:
Oil sales (per Bbl)	$	41.99	$	62.32	$	46.31	$	59.58
Oil sales with derivative settlements (per Bbl)	45.58		50.02		43.77		48.23
Natural gas sales (per Mcf)	1.17		1.95		1.71		1.99
Natural gas sales with derivative settlements (per Mcf)	1.33		2.08		1.69		2.37
NGL sales (per Bbl)	6.55		24.49		10.97		22.38
Average price (per BOE)	23.94		40.53		28.01		38.91
Average price with derivative settlements (per BOE)	26.01		34.35		26.73		33.62
Expense per BOE:
Lease operating expenses	$	3.11	$	2.91	$	3.09	$	3.11
Transportation and gathering	0.94		1.69		1.31		1.47
Production taxes	1.31		3.10		2.09		3.34
Exploration expenses	1.79		1.59		1.48		1.07
Depletion, depreciation, amortization and accretion	15.56		15.41		15.89		15.63
Impairment of long lived assets	—		2.32		0.51		0.82
General and administrative expenses	3.71		5.08		3.87		5.06
Cash general and administrative expenses⁽²⁾	2.18		2.58		2.10		2.50
Stock-based compensation	1.54		2.50		1.77		2.56
Total operating expenses per BOE	$	26.42	$	32.10	$	28.24	$	30.50

For the Three Months Ended For the Six Months Ended
June 30, June 30,
2019 2018 2019 2018
Sales (MBoe): 7,540
6,694
14,776
12,893
Oil sales (MBbl) 3,650
3,531
7,233
6,776
Natural gas sales (MMcf) 15,055
11,370
29,015
21,774
NGL sales (MBbl) 1,380
1,268
2,707
2,488
Sales (BOE/d): 82,856
73,563
81,635
71,231
Oil sales (Bbl/d) 40,113
38,804
39,962
37,436
Natural gas sales (Mcf/d) 165,445
124,941
160,302
120,297
NGL sales (Bbl/d) 15,168
13,935
14,956
13,746
Average sales prices⁽¹⁾:

Oil sales (per Bbl) $ 50.72
$ 60.46
$ 48.46
$ 58.11
Oil sales with derivative settlements (per Bbl) 43.83
48.89
42.87
47.28
Natural gas sales (per Mcf) 1.44
1.74
1.98
2.02
Natural gas sales with derivative settlements (per Mcf) 1.53
2.19
1.88
2.53
NGL sales (per Bbl) 11.04
21.22
13.24
21.21
Average price (per BOE) 29.45
38.87
30.05
38.04
Average price with derivative settlements (per BOE) 26.30
33.53
27.09
33.22
Expense per BOE:
Lease operating expenses $ 3.13
$ 3.10
$ 3.08
$ 3.22
Transportation and gathering 1.57
1.49
1.50
1.36
Production taxes 2.46
3.64
2.48
3.47
Exploration expenses 1.76
0.45
1.32
0.80
Depletion, depreciation, amortization and accretion 15.70
15.95
16.05
15.74
Impairment of long lived assets 0.40
0.02
0.76
0.01
General and administrative expenses 4.08
5.11
3.95
5.06
Cash general and administrative expenses 2.10
2.46
2.06
2.46
Stock-based compensation 1.98
2.65
1.89
2.60
Total operating expenses per BOE $ 29.10
$ 29.76
$ 29.14
$ 29.66


~~(1)~~	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.

(1)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.

(2)Cash general and administrative expenses for the three and nine months ended September 30, 2019 includes expense of $1.9 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 $1.92 and $2.01 for the three and nine months ended September 30, 2019, respectively.

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Three Months Ended ~~June~~September 30, 2019 Compared to Three Months Ended ~~June~~September 30, 2018

Oil sales revenues. Crude oil sales revenues decreased by ~~$28.4~~$74.4 million to ~~$185.1~~$151.1 million for the three months ended ~~June~~September 30, 2019 as compared to crude oil sales of ~~$213.5~~$225.5 million for the three months ended ~~June~~September 30, 2018. An ~~increase~~A decrease in sales volumes between these periods contributed ~~an $7.2~~a $1.4 million ~~positive~~negative impact, ~~while~~ and a decrease in crude oil prices contributed a ~~$35.6~~$73.1 million negative impact.

For the three months ended ~~June~~September 30, 2019, crude oil revenue decreased by approximately $22.2 million due to the impact of our updated strategy to emphasize free cash flow in 2020 and beyond, resulting in a decrease in future capital expenditures and rig counts, which decreased the future forecasted production and increased the forecasted deferral balance on one of our revenue contracts.

For the three months ended September 30, 2019, our crude oil sales averaged ~~40.1~~39.1 MBbl/d. Our crude oil sales volume ~~increased~~ 3%decreased by 1% to ~~3,650~~3,597 MBbl for the three months ended ~~June~~September 30, 2019 compared to ~~3,531~~3,618 MBbl for the three months ended ~~June~~September 30, 2018. 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 ~~127~~133 gross wells from ~~July~~October 1, 2018 to ~~June~~September 30, ~~2019, partially offset by the natural decline of our existing properties.~~2019.

The average price we realized on the sale of crude oil was ~~$50.72~~$41.99 per Bbl for the three months ended ~~June~~September 30, 2019 compared to ~~$60.46~~$62.32 per Bbl for the three months ended ~~June~~September 30, ~~2018.~~2018, primarily due to changes in market prices for crude oil and the $22.2 million decrease of crude oil revenue explained above.

Natural gas sales revenues. Natural gas sales revenues ~~increased~~decreased by ~~$1.9~~$6.3 million to ~~$21.7~~$16.8 million for the three months ended ~~June~~September 30, 2019 as compared to natural gas sales revenues of ~~$19.8~~$23.1 million for the three months ended ~~June~~September 30, 2018. An increase in sales volumes between these periods contributed ~~an $6.4~~a $5.0 million positive impact, while a decrease in natural gas prices contributed a ~~$4.5~~$11.3 million negative impact.

For the three months ended ~~June~~September 30, 2019, our natural gas sales averaged ~~165.4~~156.7 MMcf/d. Natural gas sales volumes increased by ~~32%~~22% to ~~15,055~~14,418 MMcf for the three months ended ~~June~~September 30, 2019 as compared to ~~11,370~~11,838 MMcf for the three months ended ~~June~~September 30, 2018. The volume increase is primarily due to the completion of ~~127~~133 gross wells from ~~July~~October 1, 2018 to ~~June~~September 30, 2019, partially offset by the natural decline on existing producing properties.

The average price we realized on the sale of our natural gas was ~~$1.44~~$1.17 per Mcf for the three months ended ~~June~~September 30, 2019 compared to ~~$1.74~~$1.95 per Mcf for the three months ended ~~June~~September 30, ~~2018.~~2018, primarily due to capacity constraints in transporting the wet gas associated with crude oil production coupled with negative market conditions surrounding limited export capacity.

NGL sales revenues. NGL sales revenues decreased by ~~$11.7~~$24.5 million to ~~$15.2~~$9.1 million for the three months ended ~~June~~September 30, 2019 as compared to NGL sales revenues of ~~$26.9~~$33.6 million for the three months ended ~~June~~September 30, 2018. An increase in sales volumes between these periods contributed a ~~$2.4~~$0.4 million positive impact, while a decrease in price contributed a ~~$14.1~~$24.9 million negative impact.

For the three months ended ~~June~~September 30, 2019, our NGL sales averaged ~~15.2~~15.1 MBbl/d. NGL sales volumes increased by 9%1% to ~~1,380~~1,390 MBbl for the three months ended ~~June~~September 30, 2019 as compared to ~~1,268~~1,372 MBbl for the three months ended ~~June~~September 30, 2018. The volume increase is primarily due to the completion of ~~127~~133 gross wells from ~~July~~October 1, 2018 to ~~June~~September 30, 2019, 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 ~~$11.04~~$6.55 per Bbl for the three months ended ~~June~~September 30, 2019 compared to ~~$21.22~~$24.49 per Bbl for the three months ended ~~June~~September 30, ~~2018.~~2018, primarily due to capacity constraints in transporting the wet gas associated with crude oil production coupled with negative market conditions surrounding limited export capacity.

Lease operating expenses ("LOE"). Our LOE increased by ~~$2.8~~$2.7 million to ~~$23.6~~$23.0 million for the three months ended ~~June~~September 30, 2019, from ~~$20.8~~$20.3 million for the three months ended ~~June~~September 30, 2018. The increase in LOE was primarily the result of an increase in producing wells and an increase in workover repairs, partially offset by optimization of our field cost structure during the twelve months ended ~~June~~September 30, 2019.

On a per unit basis, LOE increased to ~~$3.13~~$3.11 per BOE sold for the three months ended ~~June~~September 30, 2019 from ~~$3.10~~$2.91 per BOE for the three months ended ~~June~~September 30, 2018.

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Transportation and gathering ("T&G"). Our T&G expense ~~increased~~decreased by ~~$1.9~~$4.9 million to ~~$11.9~~$6.9 million for the three months ended ~~June~~September 30, 2019, from ~~$10.0~~$11.8 million for the three months ended ~~June~~September 30, 2018. The ~~increase~~decrease in T&G was primarily due to ~~adding more wells~~a decrease of volumes on ~~fixed fee contracts for~~a certain gathering system during the three months ended ~~June~~September 30, ~~2019.~~2019 compared to the three months ended September 30, 2018.

On a per unit basis, T&G ~~increased~~decreased to ~~$1.57~~$0.94 per BOE sold for the three months ended ~~June~~September 30, 2019 compared to ~~$1.49~~$1.69 per BOE sold for the three months ended ~~June~~September 30, 2018.

Production taxes. Our production taxes decreased by ~~$5.8~~$11.9 million to ~~$18.6~~$9.7 million for the three months ended ~~June~~September 30, 2019 as compared to ~~$24.4~~$21.6 million for the three months ended ~~June~~September 30, 2018. The decrease is primarily attributable to decreased revenue as production taxes are calculated as a percentage of sales revenue. Production taxes as a percentage of sales revenue was ~~8.4%~~5.5% for the three months ended ~~June~~September 30, 2019 as compared to ~~9.4%~~7.7% for the three months ended ~~June~~September 30, 2018. The decrease in production taxes as a percentage of sales revenue relates to a decrease in the estimated ad valorem and severance tax rates and an adjustment to the estimated ad valorem tax payable for the three months ended ~~June~~September 30, 2019.

Exploration expenses. Our exploration expenses were ~~$13.3~~$13.2 million for the three months ended ~~June~~September 30, 2019, which were primarily attributable to ~~$1.2~~$0.5 million in expense for the extension of certain leases and ~~$11.1~~$11.2 million in impairment expense related to the abandonment and impairment of unproved properties for the three months ended ~~June~~September 30, 2019. For the three months ended ~~June~~September 30, 2018, we recognized ~~$3.0~~$11.0 million in exploration expenses.

Depletion, depreciation, amortization and accretion expense ("DD&A"). Our DD&A expense increased ~~$11.6~~ $7.7 million to ~~$118.4~~$115.0 million for the three months ended ~~June~~September 30, 2019 as compared to ~~$106.8~~$107.3 million for the three months ended ~~June~~September 30, 2018. This increase is due to an increase in volumes sold for the three months ended ~~June~~September 30, 2019 as sales increased by approximately ~~846~~427 MBoe. On a per unit basis, DD&A expense ~~decreased~~increased to ~~$15.70~~$15.56 per BOE for the three months ended ~~June~~September 30, 2019 from ~~$15.95~~$15.41 per BOE for the three months ended ~~June~~September 30, 2018.

Impairment of long lived assets. ~~Our~~No impairment expense ~~of $3.0 million~~was recognized for the three months ended ~~June~~September 30, ~~2019~~2019. Impairment expense of $16.2 million expense was recognized for the three months ended September 30, 2018 related to impairment of the proved oil and gas properties in our northern field. The fair value did not exceed our carrying amount associated with the proved oil and gas properties in our northern field. Impairment expense of $0.1 million expense was recognized for the three months ended June 30, 2018.

Gain on sale of property and equipment and assets of unconsolidated subsidiary. Our gain on sale of property and equipment and assets of unconsolidated subsidiary was ~~$0.1~~$1.0 million for the three months ended ~~June~~September 30, 2019. Our gain on sale of property and equipment and assets of unconsolidated subsidiary was ~~$59.9~~$83.6 million related to our ~~April~~August 2018 ~~Divestitures~~Divestiture for the three months ended ~~June~~September 30, 2018.

General and administrative expenses ("G&A"). General and administrative expenses decreased by ~~$3.5~~$8.0 million to ~~$30.7~~$27.4 million for the three months ended ~~June~~September 30, 2019 as compared to ~~$34.2~~$35.4 million for the three months ended ~~June~~September 30, 2018. This decrease is primarily due to a decrease in stock-based compensation expense recognized for the three months ended ~~June~~September 30, 2019 compared to the three months ended ~~June~~September 30, 2018. On a per unit basis, G&A expense decreased to ~~$4.08~~$3.71 per BOE sold for the three months ended ~~June~~September 30, 2019 from ~~$5.11~~$5.08 per BOE sold for the three months ended ~~June~~September 30, 2018.

Our G&A expenses for the three months ended September 30, 2019 includes $1.9 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 September 30, 2018.

Our G&A expenses include the ~~non‑cash~~non-cash expense for ~~stock‑based~~stock-based compensation for equity awards granted to our employees and directors. For the three months ended ~~June~~September 30, 2019 and 2018, ~~stock‑based~~stock-based compensation expense was ~~$14.9~~$11.4 million and ~~$17.7~~$17.4 million, respectively.

Commodity derivative gain (loss). Primarily due to the decrease in NYMEX crude oil futures prices at ~~June~~September 30, 2019 as compared to ~~March 31,~~June 30, 2019 and change in fair value from the execution of new positions, we incurred a net gain on our commodity derivatives of ~~$73.5~~$88.0 million for the three months ended ~~June~~September 30, 2019, including the amortization of premiums. Primarily due to the increase in NYMEX crude oil futures prices at ~~June~~September 30, 2018 as compared to ~~March 31,~~June 30, 2018 and change in fair value from the execution of new positions, we incurred a net loss on our commodity derivatives of ~~$89.5~~$35.9 million for the three months ended ~~June~~September 30, 2018, 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

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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 ~~June~~September 30, 2019, ~~and~~we received cash settlements of commodity derivatives totaling $16.1 million. During the three months ended September 30, 2018, we paid cash settlements of commodity derivatives totaling ~~$14.2 million and $35.7 million, respectively.~~$41.0 million.

Interest expense. Interest expense consists of interest expense on our long-term debt and amortization of debt issuance costs, net of capitalized interest. For the three months ended ~~June~~September 30, 2019, we recognized interest expense of ~~$18.6~~$23.2 million as compared to ~~$19.2~~$20.7 million for the three months ended ~~June~~September 30, 2018, as a result of borrowings under our revolving credit facility, our 2024 Senior Notes, our 2026 Senior Notes and the amortization of debt issuance costs.

We incurred interest expense for the three months ended ~~June~~September 30, 2019 of ~~$22.2~~$23.8 million related to our 2024 Senior Notes, 2026 Senior Notes, and revolving credit facility. We incurred interest expense for the three months ended ~~June~~September 30, 2018 of approximately ~~$20.4~~$21.5 million related to our revolving credit facility, our 2024 Senior Notes, and our 2026 Senior Notes. Also

included in interest expense for the three months ended ~~June~~September 30, 2019 and 2018 was the amortization of debt issuance costs of ~~$1.3~~$1.0 million and $0.9 million, respectively. For the three months ended ~~June~~September 30, 2019 and 2018, we capitalized interest expense of ~~$1.8~~$1.6 million and ~~$2.1~~$1.7 million, respectively. ~~Interest expense for the three months ended June 30, 2019 also includes $3.2 million of gain on debt extinguishment upon the repurchase of our 2026 Senior Notes.~~

Income tax expense. We recorded an income tax expense of ~~$15.1~~$14.8 million and ~~$4.2~~$22.2 million for the three months ended ~~June~~September 30, 2019 and 2018, respectively. This resulted in an effective tax rate of approximately ~~25.8%~~30.4% and ~~32.2%~~25.4% for the three months ended ~~June~~September 30, 2019 and 2018, respectively. Our effective tax rate for the three months ended ~~June~~September 30, 2019 and 2018 differs from the U.S. statutory income tax rates of 21.0% primarily due to the effects of state income taxes and estimated taxable permanent differences.

Gathering and facilities segment. The Company has two operating segments, (i) the exploration, development and production of oil, natural gas and NGL (the "exploration and production segment") and (ii) the construction and support of midstream assets to gather and process crude oil and gas production (the "gathering and facilities segment"). Prior to the fourth quarter of 2018, the Company had a single operating segment. The gathering systems and facilities operating segment ~~is currently~~was under ~~development.~~development as of September 30, 2019. On October 3, 2019, Elevation commenced moving crude oil, natural gas and water through its Badger central gathering facility. Capital expenditures associated with gathering systems and facilities ~~are being~~were incurred to develop midstream infrastructure to support the Company's development of its oil and gas leasehold along with third-party activity and amounted to ~~$68.6~~$65.1 million and ~~$14.6~~$37.5 million for the three months ended ~~June~~September 30, 2019 and 2018, respectively. ~~Management expects that the first phase of the gathering systems and facilities will be operational at the end of the third quarter of 2019.~~

~~Six~~Nine Months Ended ~~June~~September 30, 2019 Compared to ~~Six~~Nine Months Ended ~~June~~September 30, 2018

Oil sales revenues. Crude oil sales revenues decreased by ~~$43.2~~$117.6 million to ~~$350.5~~$501.6 million for the ~~six~~nine months ended ~~June~~September 30, 2019 as compared to crude oil sales of ~~$393.7~~$619.2 million for the ~~six~~nine months ended ~~June~~September 30, 2018. An increase in sales volumes between these periods contributed ~~an $26.6~~a $26.0 million positive impact, while a decrease in crude oil prices contributed a ~~$69.8~~$143.6 million negative impact.

For the ~~six~~nine months ended ~~June~~September 30, 2019 crude oil revenue was decreased by approximately $22.2 million due to the impact of our updated strategy to emphasize free cash flow in 2020 and beyond, resulting in a decrease in future capital expenditures and rig counts, which decreased the future forecasted production and increased the forecasted deferral balance on one of our revenue contracts.

For the nine months ended September 30, 2019, our crude oil sales averaged ~~40.0~~39.7 MBbl/d. Our crude oil sales volume increased 7% 4% to ~~7,233~~10,830 MBbl for the ~~six~~nine months ended ~~June~~September 30, 2019 compared to ~~6,776~~10,394 MBbl for the ~~six~~nine months ended ~~June~~September 30, 2018. The volume increase is primarily due to an increase in production from the completion of ~~127~~133 gross wells from ~~July~~October 1, 2018 to ~~June~~September 30, 2019, partially offset by the natural decline of our existing properties.

The average price we realized on the sale of crude oil was ~~$48.46~~$46.31 per Bbl for the ~~six~~nine months ended ~~June~~September 30, 2019 compared to ~~$58.11~~$59.58 per Bbl for the ~~six~~nine months ended ~~June~~September 30, ~~2018.~~2018, primarily due to changes in market prices for crude oil and the $22.0 million decrease of crude oil revenue explained above.

Natural gas sales revenues. Natural gas sales revenues increased by ~~$13.7~~$7.4 million to ~~$57.6~~$74.4 million for the ~~six~~nine months ended ~~June~~September 30, 2019 as compared to natural gas sales revenues of ~~$43.9~~$67.0 million for the ~~six~~nine months ended ~~June~~September 30, 2018. An increase in sales volumes between these periods contributed ~~an $14.6~~a $19.5 million positive impact, while a decrease in natural gas prices contributed a ~~$0.9~~$12.1 million negative impact.

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For the ~~six~~nine months ended ~~June~~September 30, 2019, our natural gas sales averaged ~~160.3~~159.1 MMcf/d. Natural gas sales volumes increased by ~~33%~~29% to ~~29,015~~43,433 MMcf for the ~~six~~nine months ended ~~June~~September 30, 2019 as compared to ~~21,774~~33,612 MMcf for the ~~six~~nine months ended ~~June~~September 30, 2018. The volume increase is primarily due to the completion of ~~127~~133 gross wells from ~~July~~October 1, 2018 to ~~June~~September 30, 2019, partially offset by the natural decline on existing producing properties.

The average price we realized on the sale of our natural gas was ~~$1.98~~$1.71 per Mcf for the ~~six~~nine months ended ~~June~~September 30, 2019 compared to ~~$2.02~~$1.99 per Mcf for the ~~six~~nine months ended ~~June~~September 30, ~~2018.~~2018, primarily due to capacity constraints in transporting the wet gas associated with crude oil production coupled with negative market conditions surrounding limited export capacity.

NGL sales revenues. NGL sales revenues decreased by ~~$17.0~~$41.5 million to ~~$35.8~~$44.9 million for the ~~six~~nine months ended ~~June~~September 30, 2019 as compared to NGL sales revenues of ~~$52.8~~$86.4 million for the ~~six~~nine months ended ~~June~~September 30, 2018. An increase in sales volumes between these periods contributed a ~~$4.6~~$5.3 million positive impact, while a decrease in price contributed a ~~$21.6~~$46.7 million negative impact.

For the ~~six~~nine months ended ~~June~~September 30, 2019, our NGL sales averaged 15.0 MBbl/d. NGL sales volumes increased by 9%6% to ~~2,707~~4,097 MBbl for the ~~six~~nine months ended ~~June~~September 30, 2019 as compared to ~~2,488~~3,860 MBbl for the ~~six~~nine months ended ~~June~~September 30, 2018. The volume increase is primarily due to the completion of ~~127~~133 gross wells from ~~July~~October 1, 2018 to ~~June~~September 30, 2019, 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 ~~$13.24~~$10.97 per Bbl for the ~~six~~nine months ended ~~June~~September 30, 2019 compared to ~~$21.21~~$22.38 per Bbl for the ~~six~~nine months ended ~~June~~September 30, ~~2018. The decrease~~2018, primarily due to capacity constraints in ~~NGL prices during~~transporting the ~~period are~~wet gas associated with ~~capacity constraints out of the DJ Basin.~~crude oil production coupled with negative market conditions surrounding limited export capacity.

Lease operating expenses. Our LOE increased by ~~$4.0~~$6.6 million to ~~$45.5~~$68.4 million for the ~~six~~nine months ended ~~June~~September 30, 2019, from ~~$41.5~~$61.8 million for the ~~six~~nine months ended ~~June~~September 30, 2018. The increase in LOE was primarily the result of an increase in producing wells and an increase in workover repairs, partially offset by optimization of our field cost structure during the twelve months ended ~~June~~September 30, 2019.

On a per unit basis, LOE decreased to ~~$3.08~~$3.09 per BOE sold for the ~~six~~nine months ended ~~June~~September 30, 2019 from ~~$3.22~~$3.11 per BOE for the ~~six~~nine months ended ~~June~~September 30, 2018. The decrease in LOE per BOE is primarily a result of increased production volumes during the ~~six~~nine months ended ~~June~~September 30, 2019.

Transportation and gathering. Our T&G expense ~~increased~~decreased by ~~$4.7~~$0.2 million to ~~$22.2~~$29.1 million for the ~~six~~nine months ended ~~June~~September 30, 2019, from ~~$17.5~~$29.3 million for the ~~six~~nine months ended ~~June~~September 30, 2018. The ~~increase~~decrease in T&G was primarily due to ~~adding more wells~~a decrease of volumes on ~~fixed fee contracts~~a certain gathering system for the ~~six~~nine months ended ~~June~~September 30, 2019.

On a per unit basis, T&G ~~increased~~decreased to ~~$1.50~~$1.31 per BOE sold for the ~~six~~nine months ended ~~June~~September 30, 2019 compared to ~~$1.36~~$1.47 per BOE sold for the ~~six~~nine months ended ~~June~~September 30, 2018.

Production taxes. Our production taxes decreased by ~~$8.0~~$19.9 million to ~~$36.7~~$46.4 million for the ~~six~~nine months ended ~~June~~September 30, 2019 as compared to ~~$44.7~~$66.3 million for the ~~six~~nine months ended ~~June~~September 30, 2018. The decrease is primarily attributable to decreased revenue as production taxes are calculated as a percentage of sales revenue. Production taxes as a percentage of sales revenue was ~~8.3%~~7.5% for the ~~six~~nine months ended ~~June~~September 30, 2019 as compared to ~~9.1%~~8.6% for the ~~six~~nine months ended ~~June~~September 30, 2018. The decrease in production taxes as a percentage of sales revenue relates to a decrease in the estimated ad valorem and severance tax rates and an adjustment to the estimated ad valorem tax payable for the ~~six~~nine months ended ~~June~~September 30, 2019.

Exploration expenses. Our exploration expenses were ~~$19.5~~$32.7 million for the ~~six~~nine months ended ~~June~~September 30, 2019, which were primarily attributable to ~~$1.6~~$2.0 million in expense for the extension of certain leases and ~~$15.0~~$26.2 million in impairment expense related to the abandonment and impairment of unproved properties for the ~~six~~nine months ended ~~June~~September 30, 2019. For the ~~six~~nine months ended ~~June~~September 30, 2018, we recognized ~~$10.3~~$21.3 million in exploration expenses.

Depletion, depreciation, amortization and accretion expense. Our DD&A expense increased ~~$34.1~~ $41.8 million to ~~$237.1~~$352.1 million for the ~~six~~nine months ended ~~June~~September 30, 2019 as compared to ~~$203.0~~$310.3 million for the ~~six~~nine months ended ~~June~~September 30, 2018. This increase is due to an increase in volumes sold for the ~~six~~nine months ended ~~June~~September 30, 2019 as sales increased by

~~increased~~Table of Contents by

approximately ~~1,883~~2,312 MBoe. On a per unit basis, DD&A expense increased to ~~$16.05~~$15.89 per BOE for the ~~six~~nine months ended ~~June~~September 30, 2019 from ~~$15.74~~$15.63 per BOE for the ~~six~~nine months ended ~~June~~September 30, 2018.

Impairment of long lived assets. Our impairment expense of $11.2 million for the ~~six~~nine months ended ~~June~~September 30, 2019 was related to impairment of the proved oil and gas properties in our northern field. The fair value did not exceed our carrying amount associated with the proved oil and gas properties in our northern field. Impairment expense of ~~$0.1~~$16.3 million was recognized for the ~~six~~nine months ended ~~June~~September 30, 2018.

Gain on sale of property and equipment and assets of unconsolidated subsidiary. Our gain on sale of property and equipment and assets of unconsolidated subsidiary for the ~~six~~nine months ended ~~June~~September 30, 2019 was ~~$0.3~~$1.3 million. Our gain on sale of property and equipment and assets of unconsolidated subsidiary was ~~$59.9~~$143.5 million related to our April 2018 Divestitures and August 2018 Divestiture for the ~~six~~nine months ended ~~June~~September 30, 2018.

General and administrative expenses. General and administrative expenses decreased by ~~$6.8~~$14.8 million to ~~$58.4~~$85.8 million for the ~~six~~nine months ended ~~June~~September 30, 2019 as compared to ~~$65.2~~$100.6 million for the ~~six~~nine months ended ~~June~~September 30, 2018. This decrease is primarily due to a decrease in stock-based compensation expense recognized for the ~~six~~nine months ended ~~June~~September 30, 2019 compared to the ~~six~~nine months ended ~~June~~September 30, 2018. On a per unit basis, G&A expense decreased to ~~$3.95~~$3.87 per BOE sold for the ~~six~~nine months ended ~~June~~September 30, 2019 from $5.06 per BOE sold for the ~~six~~nine months ended ~~June~~September 30, 2018.

Our G&A expenses for the nine months ended September 30, 2019 includes $1.9 million related to the terms of a separation agreement with a former executive officer. No expenses of this nature were incurred during the nine months ended September 30, 2018.

Our G&A expenses include the ~~non‑cash~~non-cash expense for ~~stock‑based~~stock-based compensation for equity awards granted to our employees and directors. For the ~~six~~nine months ended ~~June~~September 30, 2019 and 2018, ~~stock‑based~~stock-based compensation expense was ~~$27.9~~$39.3 million and ~~$33.5~~$50.9 million, respectively.

Commodity derivative ~~loss.~~gain (loss). Primarily due to the ~~increase~~decrease in NYMEX crude oil futures prices at ~~June~~September 30, 2019 as compared to December 31, 2018 and change in fair value from the execution of new positions, we incurred a net ~~loss~~gain on our commodity derivatives of ~~$48.6~~$39.4 million for the ~~six~~nine months ended ~~June~~September 30, 2019, including the amortization of premiums. Primarily due to the increase in NYMEX crude oil futures prices at ~~June~~September 30, 2018 as compared to December 31, 2017 and change in fair value from the execution of new positions, we incurred a net loss on our commodity derivatives of ~~$139.8~~$175.8 million for the ~~six~~nine months ended ~~June~~September 30, 2018, including the amortization of premiums. These 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 ~~six~~nine months ended ~~June~~September 30, 2019 ~~we paid cash settlements of commodity derivatives totaling $24.5 million. During the six months ended June 30,~~and 2018, we paid cash settlements of commodity derivatives totaling ~~$58.9 million.~~$8.4 million and $99.9 million, respectively.

Interest expense. Interest expense consists of interest expense on our long-term debt and amortization of debt issuance costs, net of capitalized interest. For the ~~six~~nine months ended ~~June~~September 30, 2019, we recognized interest expense of ~~$31.6~~$54.8 million as compared to ~~$82.5~~$103.2 million for the ~~six~~nine months ended ~~June~~September 30, 2018, as a result of borrowings under our revolving credit facility, our 2021 Senior Notes, 2024 Senior Notes, our 2026 Senior Notes and the amortization of debt issuance costs.

We incurred interest expense for the ~~six~~nine months ended ~~June~~September 30, 2019 of ~~$43.0~~$66.9 million related to our 2024 Senior Notes, 2026 Senior Notes, and revolving credit facility. We incurred interest expense for the ~~six~~nine months ended ~~June~~September 30, 2018 of approximately ~~$40.2~~$61.6 million related to our revolving credit facility, our 2021 Senior Notes, 2024 Senior Notes, our 2026 Senior Notes, as well as a make-whole premium of $35.6 million related to our repayment of 2021 Senior Notes in January and February 2018. Also included in interest expense for the ~~six~~nine months ended ~~June~~September 30, 2019 and 2018 was the amortization of debt issuance costs of ~~$2.8~~$3.8 million and ~~$11.4~~$12.3 million, respectively. Amortization expense for the ~~six~~nine months ended ~~June~~September 30, 2018 includes $9.4 million of acceleration of amortization expense upon the repayment of the 2021 Senior Notes. For the ~~six~~nine months ended ~~June~~September 30, 2019 and 2018, we capitalized interest expense of ~~$3.8~~$5.4 million and ~~$4.7~~$6.3 million, respectively. Interest expense for the ~~six~~nine months ended ~~June~~September 30, 2019 also includes $10.5 million of gain on debt extinguishment upon the repurchase of our 2026 Senior Notes.

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Income tax ~~benefit.~~expense. We recorded an income tax ~~benefit~~expense of ~~$13.9~~$0.9 million and ~~$9.9~~$12.3 million for the ~~six~~nine months ended ~~June~~September 30, 2019 and 2018, respectively. This resulted in an effective tax rate of approximately ~~21.6%~~negative 5.7% and ~~18.7%~~35.9% for the ~~six~~nine months ended ~~June~~September 30, 2019 and 2018, respectively. Our effective tax rate for the ~~six~~nine months ended ~~June~~September 30, 2019 and 2018 differs from the U.S. statutory income tax rates of 21.0% primarily ~~due to the effects~~because of state income taxes and estimated taxable permanent differences. The primary differences between the tax rate of negative 5.7% and 35.9% for the nine months ended September 30, 2019 and 2018, respectively, are the increase in estimated permanent differences during the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018 and the pre-tax book loss generated for the nine months ended September 30, 2019 compared to pre-tax book income for the nine months ended September 30, 2018.

Gathering and facilities segment. The Company has two operating segments, (i) the exploration, development and production of oil, natural gas and NGL (the "exploration and production segment") and (ii) the construction and support of midstream assets to gather and process crude oil and gas production (the "gathering and facilities segment"). Prior to the fourth quarter of 2018, the Company had a single operating segment. The gathering systems and facilities operating segment ~~is currently~~was under ~~development.~~development as of September 30, 2019. On October 3, 2019, Elevation commenced moving crude oil, natural gas and water through its Badger central gathering facility. Capital expenditures associated with gathering systems and facilities are being incurred to develop midstream infrastructure to support the Company's development of its oil and gas leasehold along with third-party activity and amounted to ~~$127.5~~$192.6 million and ~~$20.2~~$57.2 million for the ~~six~~nine months ended ~~June~~September 30, 2019 and 2018, respectively. ~~Management expects that the first phase of the gathering systems and facilities will be operational at the end of the third quarter of 2019.~~

Liquidity and Capital Resources

Our primary sources of liquidity and capital resources are cash flows generated by operating activities and borrowings under our revolving credit facility. Depending upon market conditions and other factors, we may also issue equity and debt securities if needed.

Historically, our primary sources of liquidity have been borrowings under our revolving credit facility, proceeds from notes offerings, equity provided by investors, including our management team, cash from the IPO and Private Placement, cash from the issuance of preferred units, and cash flows from operations and divestitures. To date, our primary use of capital has been for the acquisition of oil and gas properties to increase our acreage position, as well as development and exploration of oil and gas properties. Our borrowings, net of unamortized debt issuance costs, were approximately ~~$1,564.7~~$1,635.2 million and $1,417.7

million at ~~June~~September 30, 2019, and December 31, 2018, respectively. We also have other contractual commitments, which are described in Note 11 – Commitments and Contingencies in Part I, Item I, 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.

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

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 2024 Senior Notes, 2026 Senior Notes and credit facility and pay dividends on our Series A Preferred Stock and the Elevation Preferred Units.

If cash flow from operations does not meet our expectations, we may 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~~

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In October 2019, we revised our 2019 capital budget for the drilling and completion of operated and non-operated wells ~~is approximately~~from a range of $585.0 million to $675.0 million ~~substantially all of which we~~to approximately $520.0 million to $550.0 million. We intend to allocate substantially all our capital budget to the Core DJ Basin. We ~~expect~~expected to drill 125 gross operated wells, complete 122 gross operated wells and turn-in-line 111 gross operated wells. As a result of the change in our capital budget, we expect to drill 108 gross operated wells, complete 118 gross operated wells and turn-in-line 113 gross operated wells. Our capital budget still anticipates a one to two operated rig drilling program and excludes up to $250.0 million for Elevation, which is fully funded by a third party and any amounts that may be paid for potential acquisitions.

~~We currently have both~~The Company had a Stock Repurchase Program in place during the nine months ended September 30, 2019. Spending under this program during this time period was $136.9 million, and the total amount repurchased under the program was $163.2 million which is the full amount authorized to be repurchased. The Company also has a Senior Notes Repurchase Program in place. Spending under ~~these programs~~this program during the ~~six~~nine months ended ~~June~~September 30, 2019 was ~~$155.0 million and we expect continued spending under these programs through 2019.~~

$39.3 million. The Company ~~was~~is authorized to repurchase ~~an incremental~~up to $100.0 million ~~in common stock from the date~~ of ~~the Extended Stock Repurchase Program, bringing the total amount authorized to be repurchased to approximately $163.2 million which has been completed as of the date of this filing.~~its Senior Notes.

Cash Flows

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


	For the Nine Months Ended
	September 30,
	2019		2018
Net cash provided by operating activities	$	356,561	$	468,362
Net cash used in investing activities	$	(706,868)	$	(678,133)
Net cash provided by financing activities	$	173,049	$	477,068

For the Six Months Ended
June 30,
2019 2018
Net cash provided by operating activities $ 218,444
$ 287,090
Net cash used in investing activities $ (449,244 ) $ (465,869 )
Net cash provided by financing activities $ 31,721
$ 240,260

~~Six~~Nine Months Ended ~~June~~September 30, 2019 Compared to ~~Six~~Nine Months Ended ~~June~~September 30, 2018

Net cash provided by operating activities. For the ~~six~~nine months ended ~~June~~September 30, 2019 as compared to the ~~six~~nine months ended ~~June~~September 30, 2018, our net cash provided by operating activities decreased by ~~$68.6~~$111.8 million, primarily due to a decrease in operating revenues net of expenses ~~$47.3~~of $139.0 million ~~from decreased sales~~as a result of a decrease in commodity prices along with a decrease of ~~$32.4~~$90.5 million onrelated to changes in working capital and an increase in cash paid for interest of $5.2 million. These decreases in net cash provided by operating activities were partially offset by a $75.0 million decrease in commodity derivative settlement payments, partially offset by an increase in sales volumes for the six months ended June 30, 2019 as compared to the six months ended June 30, 2018. Additionally, there was an increase in distributions from unconsolidated subsidiaries of $1.4 million.payments.

Net cash used in investing activities. For the ~~six~~nine months ended ~~June~~September 30, 2019 as compared to the ~~six~~nine months ended ~~June~~September 30, 2018, our net cash used in investing activities ~~decreased~~increased by ~~$16.6~~$28.7 million primarily due to ~~a decrease~~increased spending of ~~$204.2~~$127.8 million ~~used in drilling and completion activities, partially offset by an increase of $121.7 million used in~~on our gathering systems and facilities, ~~additions and~~a $20.6 million increase in other property and equipment, ~~additions. Additionally, there was an decrease in~~a $30.4 million increase from the sale of property and equipment and a $16.5 million increase in spending on our investment in unconsolidated subsidiaries. Additionally, we did not receive $82.6 million in the current period from the sale of an unconsolidated subsidiary. These increases were offset by a decrease in spending on oil and gas ~~properties~~property additions of ~~$52.4~~$248.6 million ~~during~~for the ~~six~~nine months ended ~~June~~September 30, 2019.

Net cash provided by financing activities. For the ~~six~~nine months ended ~~June~~September 30, 2019 as compared to the ~~six~~nine months ended ~~June~~September 30, 2018, our net cash provided by financing activities decreased by ~~$208.5~~$304.0 million as a result of a decrease of $739.7 million from the issuance of the 2026 Senior Notes, partially offset by an increase from redemption of the 2021 Senior Notes for $585.6 million. Net borrowings on the revolver increased $65.0 million ~~including~~offset by a ~~make-whole premium~~$49.5 million decrease in the cash received from the issuance of ~~$35.6 million.~~Elevation Preferred Units compared to the nine months ended September 30, 2019. Additionally, there was an increase ~~of the~~in cash spent to repurchase of common stock of ~~$114.2~~$133.3 million, as result of our Share Repurchase Program, and senior notes of $39.3 million, as a result of our Senior Note Repurchase Program during the ~~six~~nine months ended ~~June~~September 30, 2019.

Working Capital

Our working capital deficit was $193.2 million at September 30, 2019 and our surplus ~~(deficit)~~ was ~~$(348.9) million and~~ $62.2 million at ~~June 30, 2019 and~~ December 31, ~~2018, respectively.~~2018. Our cash balances totaled ~~$35.9~~$57.7 million and $235.0 million at ~~June~~September 30, 2019 and December 31, 2018, respectively.

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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~~As of September 30, 2019, our revolving credit facility has a maximum credit amount of $1.5 billion, subject to a borrowing base of $1.1 billion, subject to the current elected commitments of ~~$900.0 million,~~$1.0 billion, and certain of our current and future subsidiaries are or will be guarantors under such facility. Amounts repaid under our revolving credit facility may be re-borrowed from time to time, subject to the terms of the facility. For more information on the revolving credit facility, please see Note 4 — Long-Term Debt in Part 1, Item 1. Financial Information of this Quarterly Report. The revolving credit facility is secured by liens on substantially all of our properties.

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 bore interest at an annual rate of 7.875%. Interest on our 2021 Senior Notes was 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 would have matured on July 15, 2021. Our 2021 Senior Notes were guaranteed by all of our current and future restricted subsidiaries (other than Extraction Finance Corp., the co-issuer of our 2021 Senior Notes). In the first quarter of 2018, we closed a tender offer for the 2021 Senior Notes and subsequently redeemed all remaining outstanding 2021 Senior Notes. No 2021 Senior Notes remain outstanding.

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 was made on November 15, 2017. Our 2024 Senior Notes will mature on May 15, 2024. Our 2024 Senior Notes are guaranteed by certain of our current subsidiaries and by certain future restricted subsidiaries that guarantee our indebtedness under a credit facility.

In January 2018, we closed a private offering of our 2026 Senior Notes that resulted in net proceeds of approximately $737.9 million. Our 2026 Senior Notes bear interest at an annual rate of 5.625%. Interest on our 2026 Senior Notes is payable on February 1 and August 1 of each year, and the first interest payment was made on August 1, 2018. Our 2026 Senior Notes will mature on February 1, 2026. Our 2026 Senior Notes are guaranteed by certain of our current subsidiaries and by certain future restricted subsidiaries that guarantee our indebtedness under a credit facility.

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 each May 1 and November 1, 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 ~~June~~September 30, 2019, the borrowing base was $1.1 billion, subject to current elected commitments of ~~$900.0~~$1.0 billion.

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

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an applicable margin ranging from 100 to 200 basis points, depending on the percentage of our borrowing base utilized. As of ~~June~~September 30, 2019, we had ~~$480.0~~$550.0 million of 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, with the exception of Elevation. 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;

•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 and our restricted subsidiaries' consolidated current assets (includes unused commitments under our revolving credit facility and excludes derivative assets) to our restricted subsidiaries' 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.

2021 Senior Notes

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

On February 17, 2018, we redeemed the approximately $49.4 million aggregate principal amount of the 2021 Senior Notes that remained outstanding after the Tender Offer and made a cash payment of approximately $52.7 million to the remaining holders of the 2021 Senior Notes, which included a make-whole premium of $3.0 million and accrued and unpaid interest of approximately $0.3 million. No 2021 Senior Notes remain outstanding.

2024 Senior Notes

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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 2024 Senior Notes at 101% of the principal amount of the 2024 Senior 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 guarantee our indebtedness under a credit facility. The 2024 Senior 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 2024 Senior Notes.

2026 Senior Notes

In January 2018, we closed a private offering of our 2026 Senior Notes that resulted in net proceeds of approximately $737.9 million. Our 2026 Senior Notes bear interest at an annual rate of 5.625%. Interest on the 2026 Senior Notes is payable on February 1 and August 1 of each year, and the first interest payment was made on August 1, 2018. Our 2026 Senior Notes will mature on February 1, 2026. As of ~~the date of this filing,~~November 8, 2019, we ~~have~~had repurchased 2026 Senior Notes with a nominal value of $49.8 million for $39.3 million in connection with the Senior Notes Repurchase Program.

We may, at our option, redeem all or a portion of our 2026 Senior Notes at any time on or after February 1, 2021 at the redemption prices set forth in the indenture governing the 2026 Senior Notes. We are also entitled to redeem up to 35% of the aggregate principal amount of our 2026 Senior Notes before February 1, 2021, with an amount of cash not greater than the net proceeds that we raise in certain equity offerings at a redemption price equal to 105.625% of the principal amount of our 2026 Senior Notes being redeemed plus accrued and unpaid interest, if any, to the redemption date. In addition, prior to February 1, 2021, we may redeem some or all of our 2026 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 2026 Senior Notes may have the right to require us to repurchase their 2026 Senior Notes at 101% of the principal amount of the 2026 Senior Notes, plus accrued and unpaid interest, if any, to the date of purchase.

Our 2026 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 2026 Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by certain of our current subsidiaries and by certain future restricted subsidiaries that guarantee our indebtedness under a credit facility. The 2026 Senior 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 2026 Senior Notes.

Series A Preferred Stock

The holders of our 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). 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 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 trades at or above a certain premium to our initial offering price, such premium to decrease with time. On October 15, 2019, the three year anniversary had passed for the Series A Preferred Stock to convert into our common stock. We can now redeem the Series A Preferred Stock at any time for the liquidation preference, which is $185.3 million. In certain situations, including a change of control, the Series A Preferred Stock may be redeemed for cash in an amount equal to the greater of (i) 135% of the liquidation preference of the Series A Preferred Stock and (ii) a 17.5% annualized internal rate of return on the liquidation preference of the Series A Preferred Stock. The Series A Preferred Stock

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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 Annual Report.

Elevation Preferred Units

On July 3, 2018, Elevation entered into the Securities Purchase Agreement with the Purchaser, pursuant to which Elevation agreed to sell 150,000 Elevation Preferred Units at a price of $990 per Elevation Preferred Unit with an aggregate liquidation preference of $150.0 million, in a transaction exempt from the registration requirements under the Securities Act. The Private Placement closed on July 3, 2018 and resulted in net proceeds of approximately $141.9 million, $25.4 million of which was a reimbursement for previously incurred midstream capital expenditures and general and administrative expenses. These Elevation Preferred Units are non-recourse to Extraction, minimizing risk to our common shareholders, and represent the noncontrolling interest presented on the condensed consolidated statement of changes in stockholders' equity. Elevation is a separate 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 of ~~June~~September 30, 2019, ~~$14.4~~$49.9 million of cash was held by Elevation and is earmarked for construction of pipeline infrastructure to serve the development of acreage in its Hawkeye and Southwest Wattenberg areas.

During the Commitment Period, subject to the satisfaction of certain financial and operational metrics and certain other customary closing conditions, Elevation has the right to require the Purchaser to purchase additional Elevation Preferred Units on the terms set forth in the Securities Purchase Agreement. Elevation may require the Purchaser to purchase additional Elevation Preferred Units, in increments of at least $25.0 million, up to an aggregate amount of ~~$350.0~~$250.0 million. During the Commitment Period, 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 ~~$350.0~~$250.0 million commitment.

On July 10, 2019, Elevation closed on an additional 100,000 Elevation Preferred Units under ~~the~~an existing securities purchase agreement with a third party, pursuant to which Elevation had agreed to sell an additional 100,000 Elevation Preferred Units ~~of Elevation~~ at a price of $990 per Elevation Preferred Unit with an aggregate liquidation preference of $100.0 million, and resulting in net proceeds of approximately ~~$99.0 million.~~$96.5 million, after deducting discounts and related offering expenses. These Elevation Preferred Units are non-recourse to Extraction. As part of the transaction, Extraction also 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. By way of comparison, Extraction drilled a total of 90 gross wells during the nine months ended September 30, 2019.

The Elevation Preferred Units will 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.

Critical Accounting Policies and Estimates

There were no changes to our critical accounting policies from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2018.

Recent Accounting Pronouncements

Please read Note 2 2—Basis of Presentation, Restatement, Significant Accounting Policies and Recent Accounting Pronouncements of the notes to the unaudited condensed consolidated financial statements included in Item 1 of this Quarterly Report for a detailed list of recent accounting pronouncements.

Impact of Inflation/Deflation and Pricing

All of our transactions are denominated in U.S. dollars. Typically, as prices for oil and natural gas increase, associated costs rise. Conversely, as prices for oil and natural gas decrease, costs decline. Cost declines tend to lag and may not adjust downward in proportion to decline commodity prices. Historically, field-level prices received for our oil and natural gas production have been volatile. During the year ended December 31, 2018, commodity prices increased during the first, second and third quarter, and subsequently decreased in the fourth quarter, while during the years ended December 31, 2017 and 2016, commodity prices generally increased. During the ~~six~~nine months ended ~~June~~September 30, 2019, commodity prices ~~increased.~~decreased compared to the same period in 2018. 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~~Off-Balance Sheet Arrangements

As of ~~June~~September 30, 2019, we did not have material off-balance sheet arrangements, except for an agreement with our oil marketer. 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 barrelsarrangements.

Table of ~~crude oil in excess of their minimum volume commitment through October 31, 2020, subject to an evergreen provision thereafter. Please see~~ ~~Note 11 – Commitments and Contingencies~~ ~~in Part 1, Item 1 of this Quarterly Report.~~Contents

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

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

Commodity Price Risk

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

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

~~The following tables present our~~

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For a summary of the Company’s commodity derivative ~~positions related to crude oil and natural gas sales in effect~~contracts as of ~~June~~September 30, ~~2019:~~2019, please see Note 5—Commodity Derivative Instruments in Part 1, Item 1 of this Quarterly Report.

2019 2020 2021
NYMEX WTI Crude Swaps:
Notional volume (Bbl) 4,400,000
4,400,000
1,800,000
Weighted average fixed price ($/Bbl) $ 56.65
$ 60.09
$ 59.80
NYMEX WTI Crude Purchased Puts:
Notional volume (Bbl) 3,200,000
11,025,000
1,800,000
Weighted average purchased put price ($/Bbl) $ 55.31
$ 54.99
$ 55.02
NYMEX WTI Crude Sold Calls:
Notional volume (Bbl) 2,600,000
11,025,000
1,800,000
Weighted average sold call price ($/Bbl) $ 64.17
$ 62.40
$ 63.70
NYMEX WTI Crude Sold Puts:
Notional volume (Bbl) 3,000,000
15,000,000
3,600,000
Weighted average sold put price ($/Bbl) $ 43.93
$ 42.79
$ 43.58
NYMEX HH Natural Gas Swaps:
Notional volume (MMBtu) 18,000,000
35,400,000
—
Weighted average fixed price ($/MMBtu) $ 2.75
$ 2.75
$ —
NYMEX HH Natural Gas Purchased Puts:
Notional volume (MMBtu) —
600,000
—
Weighted average purchased put price ($/MMBtu) $ —
$ 2.90
$ —
NYMEX HH Natural Gas Sold Calls:
Notional volume (MMBtu) —
600,000
—
Weighted average sold call price ($/MMBtu) $ —
$ 3.48
$ —
CIG Basis Gas Swaps:
Notional volume (MMBtu) 22,200,000
43,200,000
��
Weighted average fixed basis price ($/MMBtu) $ (0.72 ) $ (0.61 ) $ —

As of ~~June~~September 30, 2019, the fair market value of our oil derivative contracts was a net asset of ~~$24.9~~$95.2 million. Based on our open oil derivative positions at ~~June~~September 30, 2019, a 10% increase in the NYMEX WTI price would decrease our net oil derivative asset by approximately ~~$113.4~~$92.4 million, while a 10% decrease in the NYMEX WTI price would increase our net oil derivative asset by approximately ~~$102.1~~$84.1 million. As of ~~June~~September 30, 2019, the fair market value of our natural gas derivative contracts was a net asset of ~~$11.0~~$12.6 million. Based upon our open commodity derivative positions at ~~June~~September 30, 2019, a 10% increase in the NYMEX Henry Hub price would decrease our net natural gas derivative asset by approximately ~~$9.3~~$7.6 million, while a 10% decrease in the NYMEX Henry Hub price would increase our net natural gas derivative asset by approximately ~~$9.4~~$7.6 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 which can be predicted with certainty. For the ~~six~~nine months ended ~~June~~September 30, 2019, 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 ~~June~~September 30, 2019, we had commodity derivative contracts with ~~nine~~ten counterparties. We do not require collateral or other security from counterparties to support derivative instruments; however, to minimize the credit risk in derivative instruments, it is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. Additionally, we use master netting agreements to minimize credit risk exposure. The creditworthiness of our counterparties is subject to periodic review. For the three and ~~six~~nine months ended ~~June~~September 30, 2019 and 2018, we did not incur any losses with respect to counterparty contracts. None of our existing derivative instrument contracts contain credit risk related contingent features.

Interest Rate Risk

At ~~June~~September 30, 2019, we had ~~$480.0~~$550.0 million variable-rate debt outstanding. The impact on interest expense of a 1% increase or decrease in the average interest rate would be approximately ~~$4.8~~$5.5 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.”

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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~~disclosure.

At the time ~~periods specified in~~we filed Amendment No. 1 on Form 10-Q/A for the ~~rules~~period ended September 30, 2019 on November 8, 2019, our principal executive officer and ~~forms~~principal financial officer had concluded that as of September 30, 2019, the end of the ~~SEC. Based upon~~period covered by this report, our disclosure controls and procedures were effective. Subsequent to that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were not effective as of September 30, 2019 because of a material weakness identified in our internal control over financial reporting. The Company is amending this Item 4 to reflect this conclusion.

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

Plan for Remediation of Material Weakness

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 is currently in the process of developing a remediation plan to address the material weakness. The remediation plan is being implemented and includes further determination regarding 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 currently plans to commence the evaluation of its updated design of internal controls for implementation expeditiously.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the three months ended ~~June~~September 30, 2019 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

~~From time to time, we are party to ongoing~~Information regarding our legal proceedings can found in ~~the ordinary course of business. While the outcome of these proceedings cannot be predicted with certainty, we do not believe the results of these proceedings, individually or~~Note 11 – Commitments and Contingencies - Litigation and Legal Items to our condensed consolidated financial statements included elsewhere in ~~the aggregate, will have a material adverse effect on our business, financial condition, results of operations or liquidity.~~this report.

ITEM 1A. RISK FACTORS

Factors that could materially adversely affect our business, financial condition, operating results or liquidity and the trading price of our common stock are described under Item 1A “Risk Factors”, included in our Quarterly Report on Form 10-Q filed with the SEC on May 2, 2019 and under Item 1A "Risk Factors", included in our Annual Report on Form 10-K filed with the SEC on February 21, 2019. 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 restated prior financial statements, which may lead to additional risks and uncertainties, including increased possibility of legal proceedings and loss of investor confidence.

We have restated our condensed consolidated financial statements as of and for the three and nine months ended September 30, 2019 in order to correct certain accounting errors as described in Note 2—Basis of Presentation, Restatement, Significant Accounting Policies and Recent Accounting Pronouncements to the condensed consolidated financial statements (the “Restatement”). For a description of the material weakness in our internal control over financial reporting identified by management in connection with the Restatement and management’s plan to remediate the material weakness, see “Part I, Item 4—Controls and Procedures.” As a result of the Restatement, we have become subject to possible additional costs for accounting and legal fees in connection with or related to the restatement and additional risks and uncertainties, including, among others, the increased possibility of legal proceedings, shareholder lawsuits or a review by the SEC and other regulatory bodies, which could cause investors to lose confidence in our reported financial information and could subject us to civil or criminal penalties, shareholder class actions or derivative actions. We could face monetary judgments, penalties or other sanctions that could have a material adverse effect on our business, financial condition and results of operations and could cause our stock price to decline.

We have identified a material weakness in our internal control over financial reporting that, if not remediated, could result in additional material misstatements in our financial statements.

As described in “Part I, Item 4—Controls and Procedures” and Note 2—Basis of Presentation, Restatement, Significant Accounting Policies and Recent Accounting Pronouncements to the condensed consolidated financial statements, management identified a control deficiency that represents a material weakness. A material weakness is a deficiency, or a 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. As a result of the identified material weakness, management has concluded that we did not maintain effective internal control over financial reporting as of September 30, 2019.

We are developing and implementing a remediation plan to address the material weakness. If our remediation efforts are insufficient or if additional material weaknesses in our internal control over financial reporting are discovered or occur in the future, our consolidated financial statements may contain material misstatements and we could be required to restate our financial results, which could materially and adversely affect our business, results of operations and financial condition, restrict our ability to access the capital markets, require us to expend significant resources to correct the material weakness, subject us to fines, penalties or judgments, harm our reputation or otherwise cause a decline in investor confidence.

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

The following table sets forth our share repurchase activity for ~~each~~the period presented:


Period	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Program	Approximate Dollar Value of Shares that May Yet be Purchased under the Plans or Programs (in millions) ⁽¹⁾
July 1, 2019 - July 31, 2019	4,807,150	$	4.42	4,807,150	$	—

Period Total Number of Shares Purchased Average Price Paid per Share Total Number of Shares Purchased as Part of Publicly Announced Plans or Program
Approximate Dollar Value of Shares that May Yet be Purchased under the Plans or Programs (in millions) ⁽¹⁾
April 1, 2019 - April 30, 2019 1,282,232
$ 4.31
1,282,232
$ 100.0
May 1, 2019 - May 31, 2019 2,302,175
$ 3.91
2,302,175
$ 91.0
June 1, 2019 - June 30, 2019 18,100,209
$ 3.85
18,100,209
$ 21.2
Total 21,684,616
$ 3.89
21,684,616
$ 21.2


~~(1)~~	On April 1, 2019, we announced an extension of our ongoing repurchase program until December 31, 2019 and an increase of the program to authorize repurchases up to an incremental amount of $100.0 million in common stock from the date of the extension, bringing the total amount authorized to be repurchased to approximately $163.2 million.

(1)On April 1, 2019, we announced an extension of our ongoing repurchase program until December 31, 2019 and an increase of the program to authorize repurchases up to an incremental amount of $100.0 million in common stock from the date of the extension, bringing the total amount authorized to be repurchased to approximately $163.2 million. The July 2019 share repurchase completed the authorized Share Repurchase Program.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

None.

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						Certificate of Designations of Series A Preferred Stock of Extraction Oil & Gas, Inc., filed with the Secretary of State of the State of Delaware on October 17, 2016 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K (File No. 001-37907) filed with the Commission on October 21, 2016).
3.3						Bylaws of Extraction Oil & Gas, Inc., dated October 11, 2016 (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K (File No. 001-37907) filed with the Commission on October 14, 2016).
~~10.1~~10.1						Master Assignment and Amendment No. 78 to Amended and Restated Credit Agreement, dated as of ~~June 27,~~August 28, 2019, by and among Extraction Oil & Gas, Inc., as borrower, certain of its subsidiaries, as guarantors, the lenders party thereto, and Wells Fargo Bank, National Association, as administrative agent and issuing lender (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 ~~July 01,~~August 30, 2019).
10.2						Separation and General Release Agreement, dated September 4, 2019, between Extraction Oil & Gas, Inc., XOG Services, LLC. and Russell T. Kelley, Jr. (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 September 4, 2019).
10.3†						Indemnification Agreement (Audrey Robertson) (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K (File No. 001-37907) filed with the Commission on September 19, 2019).
10.4						Borrowing Base Decrease Agreement, dated as of November 4, 2019, among Extraction Oil & Gas, Inc., as borrower, certain subsidiaries of Extraction Oil & Gas, Inc., as guarantors, the lenders party thereto and Wells Fargo Bank, National Association, as administrative agent (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 November 7, 2019).
*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

* Filed herewith.

** Furnished herewith.

† Management contract or compensatory plan or agreement.

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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: ~~August 1,~~December 23, 2019.


			Extraction Oil & Gas, Inc.

			~~Extraction Oil & Gas, Inc.~~
By:
	~~By:~~	/S/ MATTHEW R. OWENS
				Matthew R. Owens
				President and Acting 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, 2019		December 31, 2018
	June 30, 2019			December 31, 2018				As restated
ASSETS							ASSETS
Current Assets:							Current Assets:
Cash and cash equivalents	$	35,907		$	234,986		Cash and cash equivalents	$	57,728	$	234,986
Accounts receivable							Accounts receivable
Trade	35,636			41,695			Trade	55,095		41,695
Oil, natural gas and NGL sales	86,024			91,225			Oil, natural gas and NGL sales	69,750		91,225
Inventory and prepaid expenses	18,081			26,816
Inventory, prepaid expenses and other							Inventory, prepaid expenses and other	28,854		26,816
Commodity derivative asset	11,959			48,907			Commodity derivative asset	66,480		48,907
Assets held for sale	—			21,008			Assets held for sale	—		21,008
Total Current Assets	187,607			464,637			Total Current Assets	277,907		464,637
Property and Equipment (successful efforts method), at cost:							Property and Equipment (successful efforts method), at cost:
Proved oil and gas properties	4,349,144			3,916,622			Proved oil and gas properties	4,494,226		3,916,622
Unproved oil and gas properties	595,281			609,284			Unproved oil and gas properties	572,400		609,284
Wells in progress	117,765			144,323			Wells in progress	104,429		144,323
Less: accumulated depletion, depreciation and amortization	(1,388,727		)	(1,152,590		)	Less: accumulated depletion, depreciation and amortization	(1,498,608)		(1,152,590)
Net oil and gas properties	3,673,463			3,517,639			Net oil and gas properties	3,672,447		3,517,639
Gathering systems and facilities	241,939			114,469			Gathering systems and facilities	307,038		114,469
Other property and equipment, net of accumulated depreciation	64,882			39,849			Other property and equipment, net of accumulated depreciation	73,265		39,849
Net Property and Equipment	3,980,284			3,671,957			Net Property and Equipment	4,052,750		3,671,957
Non-Current Assets:							Non-Current Assets:
Commodity derivative asset	27,671			8,432			Commodity derivative asset	41,520		8,432
Other non-current assets	56,987			21,001			Other non-current assets	69,290		21,001
Total Non-Current Assets	84,658			29,433			Total Non-Current Assets	110,810		29,433
Total Assets	$	4,252,549		$	4,166,027		Total Assets	$	4,441,467	$	4,166,027
LIABILITIES AND STOCKHOLDERS' EQUITY							LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:							Current Liabilities:
Accounts payable and accrued liabilities	$	280,470		$	186,218		Accounts payable and accrued liabilities	$	216,194	$	186,218
Revenue payable	94,310			117,344			Revenue payable	96,140		117,344
Production taxes payable	120,964			57,516			Production taxes payable	114,969		57,516
Commodity derivative liability	3,541			196			Commodity derivative liability	108		196
Accrued interest payable	19,647			22,249			Accrued interest payable	17,272		22,249
Asset retirement obligations	17,528			15,729			Asset retirement obligations	26,426		15,729
Liabilities related to assets held for sale	—			3,146			Liabilities related to assets held for sale	—		3,146
Total Current Liabilities	536,460			402,398			Total Current Liabilities	471,109		402,398
Non-Current Liabilities:							Non-Current Liabilities:
Credit facility	480,000			285,000			Credit facility	550,000		285,000
Senior Notes, net of unamortized debt issuance costs	1,084,667			1,132,659			Senior Notes, net of unamortized debt issuance costs	1,085,217		1,132,659
Production taxes payable	48,893			115,607			Production taxes payable	70,560		115,607
Commodity derivative liability	134			—			Commodity derivative liability	83		—
Other non-current liabilities	21,237			8,072			Other non-current liabilities	55,752		8,072
Asset retirement obligations	71,972			54,062			Asset retirement obligations	67,500		54,062
Deferred tax liability	95,276			109,176			Deferred tax liability	110,076		109,176
Total Non-Current Liabilities	1,802,179			1,704,576			Total Non-Current Liabilities	1,939,188		1,704,576
Total Liabilities	2,338,639			2,106,974			Total Liabilities	2,410,297		2,106,974
Commitments and Contingencies—Note 11							Commitments and Contingencies—Note 11
Series A Convertible Preferred Stock, $0.01 par value; 50,000,000 shares authorized; 185,280 issued and outstanding	167,601			164,367			Series A Convertible Preferred Stock, $0.01 par value; 50,000,000 shares authorized; 185,280 issued and outstanding	169,282		164,367
Stockholders' Equity:							Stockholders' Equity:
Common stock, $0.01 par value; 900,000,000 shares authorized; 142,535,967 and 171,666,485 issued and outstanding	1,384			1,678
Treasury stock, at cost, 34,051,928 and 4,543,262 shares	(148,939		)	(32,737		)
Common stock, $0.01 par value; 900,000,000 shares authorized; 138,073,124 and 171,666,485 issued and outstanding							Common stock, $0.01 par value; 900,000,000 shares authorized; 138,073,124 and 171,666,485 issued and outstanding	1,336		1,678
Treasury stock, at cost, 38,859,078 and 4,543,262 shares							Treasury stock, at cost, 38,859,078 and 4,543,262 shares	(170,138)		(32,737)
Additional paid-in capital	2,164,295			2,153,661			Additional paid-in capital	2,164,921		2,153,661
Accumulated deficit	(426,376		)	(375,788		)	Accumulated deficit	(392,452)		(375,788)
Total Extraction Oil & Gas, Inc. Stockholders' Equity	1,590,364			1,746,814			Total Extraction Oil & Gas, Inc. Stockholders' Equity	1,603,667		1,746,814
Noncontrolling interest	155,945			147,872			Noncontrolling interest	258,221		147,872
Total Stockholders' Equity	1,746,309			1,894,686			Total Stockholders' Equity	1,861,888		1,894,686
Total Liabilities and Stockholders' Equity	$	4,252,549		$	4,166,027		Total Liabilities and Stockholders' Equity	$	4,441,467	$	4,166,027



	For the Six Months Ended June 30,
	2019			2018
Cash flows from operating activities:
Net loss	$	(50,588	)	$	(43,147	)
Reconciliation of net loss to net cash provided by operating activities:
Depletion, depreciation, amortization and accretion	237,138			202,981
Abandonment and impairment of unproved properties	14,993			5,922
Impairment of long lived assets	11,233			128
Gain on sale of property and equipment	(319		)	(59,902		)
Gain on repurchase of 2026 Senior Notes	(10,486		)	—
Amortization of debt issuance costs	2,826			11,368
Non-cash lease expense	5,058			—
Deferred rent	—			280
Commodity derivatives loss	48,572			139,839
Settlements on commodity derivatives	(21,918		)	(54,279		)
Premiums paid on commodity derivatives	(2,852		)	(17,271		)
Earnings in unconsolidated subsidiaries	(576		)	(1,043		)
Distributions from unconsolidated subsidiaries	1,990			626
Make-whole premium expense on 2021 Senior Notes	—			35,600
Deferred income tax benefit	(13,900		)	(9,900		)
Stock-based compensation	27,945			33,464
Changes in current assets and liabilities:
Accounts receivable—trade	4,163			5,101
Accounts receivable—oil, natural gas and NGL sales	5,201			(66		)
Inventory and prepaid expenses	600			(812		)
Accounts payable and accrued liabilities	(2,973		)	(10,248		)
Revenue payable	(23,553		)	35,138
Production taxes payable	(3,461		)	19,741
Accrued interest payable	(2,602		)	(1,396		)
Asset retirement expenditures	(8,047		)	(5,034		)
Net cash provided by operating activities	218,444			287,090
Cash flows from investing activities:
Oil and gas property additions	(314,975		)	(519,154		)
Sale of property and equipment	19,982			72,345
Gathering systems and facilities additions	(115,337		)	(16,055		)
Other property and equipment additions	(25,161		)	(2,712		)
Investment in unconsolidated subsidiaries	(14,962		)	(293		)
Distributions from unconsolidated subsidiary, return of capital	1,209			—
Net cash used in investing activities	(449,244		)	(465,869		)
Cash flows from financing activities:
Borrowings under credit facility	245,000			430,000
Repayments under credit facility	(50,000		)	(330,000		)
Proceeds from the issuance of 2026 Senior Notes	—			739,664
Repayments of 2021 Senior Notes	—			(550,000		)
Make-whole premium paid on 2021 Senior Notes	—			(35,600		)
Repurchase of 2026 Senior Notes	(39,325		)	—
Repurchase of common stock	(116,496		)	(2,309		)
Payment of employee payroll withholding taxes	(582		)	(2,531		)
Dividends on Series A Preferred Stock	(5,443		)	(5,443		)
Debt and equity issuance costs	(1,433		)	(3,521		)
Net cash provided by financing activities	31,721			240,260
Increase (decrease) in cash, cash equivalents and restricted cash	(199,079		)	61,481
Cash, cash equivalents and restricted cash at beginning of period	234,986			6,768
Cash, cash equivalents and restricted cash at end of the period	$	35,907		$	68,249


	For the Nine Months Ended September 30,
	2019		2018
Cash flows from operating activities:	As restated
Net income (loss)	$	(16,664)	$	22,003
Reconciliation of net income (loss) to net cash provided by operating activities:
Depletion, depreciation, amortization and accretion	352,134		310,296
Abandonment and impairment of unproved properties	26,166		15,463
Impairment of long lived assets	11,233		16,294
Gain on sale of property and equipment	(319)		(59,849)
Gain on sale of assets of unconsolidated subsidiary	(1,010)		(83,612)
Gain on repurchase of 2026 Senior Notes	(10,486)		—
Amortization of debt issuance costs	3,799		12,303
Non-cash lease expense	7,739		—
Contract asset (liability)	22,175		—
Deferred rent	—		442
Commodity derivatives (gain) loss	(39,383)		175,752
Settlements on commodity derivatives	(18,527)		(93,482)
Premiums paid on commodity derivatives	(2,852)		(17,271)
Earnings in unconsolidated subsidiaries	(1,217)		(1,886)
Distributions from unconsolidated subsidiaries	2,630		1,684
Make-whole premium paid on 2021 Senior Notes	—		35,600
Deferred income tax expense	900		12,300
Stock-based compensation	39,306		50,883
Changes in current assets and liabilities:
Accounts receivable—trade	(1,395)		4,573
Accounts receivable—oil, natural gas and NGL sales	16,293		(13,865)
Inventory, prepaid expenses and other	1,078		(637)
Accounts payable and accrued liabilities	(6,469)		(14,780)
Revenue payable	(21,723)		60,946
Production taxes payable	12,211		49,657
Accrued interest payable	(4,977)		(5,015)
Asset retirement expenditures	(14,081)		(9,437)
Net cash provided by operating activities	356,561		468,362
Cash flows from investing activities:
Oil and gas property additions	(526,187)		(774,787)
Sale of property and equipment	41,982		72,345
Gathering systems and facilities additions	(169,180)		(41,359)
Other property and equipment additions	(32,575)		(11,944)
Investment in unconsolidated subsidiaries	(22,487)		(6,000)
Distributions from unconsolidated subsidiary, return of capital	569		—
Sale of assets of unconsolidated subsidiary	1,010		83,612
Net cash used in investing activities	(706,868)		(678,133)
Cash flows from financing activities:
Borrowings under credit facility	375,000		590,000
Repayments under credit facility	(110,000)		(390,000)
Proceeds from the issuance of 2026 Senior Notes	—		739,664
Repayments of 2021 Senior Notes	—		(550,000)
Make-whole premium paid on 2021 Senior Notes	—		(35,600)
Repurchase of 2026 Senior Notes	(39,325)		—
Repurchase of commons stock	(137,743)		(4,434)
Payment of employee payroll withholding taxes	(1,164)		(2,862)
Dividends on Series A Preferred Stock	(8,164)		(8,164)
Debt and equity issuance costs	(2,055)		(3,103)
Proceeds from issuance of Preferred Units	99,000		148,500
Preferred Unit issuance costs	(2,500)		(6,933)
Net cash provided by financing activities	173,049		477,068
(Decrease) increase in cash and cash equivalents	(177,258)		267,297
Cash, cash equivalents and restricted cash at beginning of period	234,986		6,768
Cash, cash equivalents and restricted cash at end of the period	$	57,728	$	274,065
Supplemental cash flow information:
Property and equipment included in accounts payable and accrued liabilities	$	158,178	$	148,156
Cash paid for interest	$	71,878	$	66,673
Issuance of promissory note to unconsolidated subsidiary	$	—	$	35,329
Extinguishment of promissory note in exchange for equity with unconsolidated subsidiary	$	—	$	(35,329)
Accretion of beneficial conversion feature of Series A Preferred Stock	$	4,915	$	4,429
Preferred Units paid-in-kind commitment fees and dividends	$	13,849	$	3,305


	Nine Months Ended September 30, 2019
Cash paid for amounts included in the measurements of lease liabilities
Operating cash flows from operating leases	$	(9,014)
Right-of-use assets obtained in exchange for lease obligations
Operating leases	$	(2,997)



	Six Months Ended June 30, 2019
Cash paid for amounts included in the measurements of lease liabilities
Operating cash flows from operating leases	$	(5,789	)
Right-of-use assets obtained in exchange for lease obligations
Operating leases	$	(2,234	)



☒			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)


														For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	For the Three Months Ended June 30,						For the Six Months Ended June 30,							2019		2018		2019		2018
	2019			2018			2019			2018				As restated				As restated
Revenues:													Revenues:
Oil sales	$	185,125		$	213,481		$	350,549		$	393,744		Oil sales	$	151,042	$	225,467	$	501,591	$	619,211
Natural gas sales	21,692			19,807			57,584			43,888			Natural gas sales	16,801		23,103		74,385		66,991
NGL sales	15,240			26,908			35,841			52,779			NGL sales	9,099		33,590		44,940		86,369
Total Revenues	222,057			260,196			443,974			490,411			Total Revenues	176,942		282,160		620,916		772,571
Operating Expenses:													Operating Expenses:
Lease operating expenses	23,608			20,774			45,465			41,477			Lease operating expenses	22,979		20,283		68,445		61,760
Transportation and gathering	11,854			9,959			22,219			17,498			Transportation and gathering	6,922		11,786		29,142		29,284
Production taxes	18,580			24,389			36,709			44,712			Production taxes	9,711		21,605		46,419		66,317
Exploration expenses	13,287			3,021			19,481			10,288			Exploration expenses	13,245		11,038		32,725		21,326
Depletion, depreciation, amortization and accretion	118,368			106,774			237,138			202,981			Depletion, depreciation, amortization and accretion	114,996		107,315		352,134		310,296
Impairment of long lived assets	2,985			128			11,233			128			Impairment of long lived assets	—		16,166		11,233		16,294
Gain on sale of property and equipment	(97		)	(59,902		)	(319		)	(59,902		)
Gain on sale of property and equipment and assets of unconsolidated subsidiary													Gain on sale of property and equipment and assets of unconsolidated subsidiary	(1,011)		(83,559)		(1,329)		(143,461)
General and administrative expenses	30,740			34,231			58,392			65,200			General and administrative expenses	27,445		35,365		85,835		100,565
Total Operating Expenses	219,325			139,374			430,318			322,382			Total Operating Expenses	194,287		139,999		624,604		462,381
Operating Income	2,732			120,822			13,656			168,029
Operating Income (Loss)													Operating Income (Loss)	(17,345)		142,161		(3,688)		310,190
Other Income (Expense):													Other Income (Expense):
Commodity derivatives gain (loss)	73,519			(89,511		)	(48,572		)	(139,839		)	Commodity derivatives gain (loss)	87,956		(35,913)		39,383		(175,752)
Interest expense	(18,558		)	(19,202		)	(31,566		)	(82,504		)	Interest expense	(23,224)		(20,725)		(54,791)		(103,229)
Other income	851			939			1,994			1,267			Other income	1,337		1,827		3,332		3,094
Total Other Income (Expense)	55,812			(107,774		)	(78,144		)	(221,076		)	Total Other Income (Expense)	66,069		(54,811)		(12,076)		(275,887)
Income (Loss) Before Income Taxes	58,544			13,048			(64,488		)	(53,047		)	Income (Loss) Before Income Taxes	48,724		87,350		(15,764)		34,303
Income tax (expense) benefit	(15,100		)	(4,200		)	13,900			9,900
Income tax expense													Income tax expense	(14,800)		(22,200)		(900)		(12,300)
Net Income (Loss)	$	43,444		$	8,848		$	(50,588	)	$	(43,147	)	Net Income (Loss)	$	33,924	$	65,150	$	(16,664)	$	22,003
Net income attributable to noncontrolling interest	4,097			—			8,072			—			Net income attributable to noncontrolling interest	5,776		3,305		13,849		3,305
Net Income (Loss) Attributable to Extraction Oil & Gas, Inc.	39,347			8,848			(58,660		)	(43,147		)	Net Income (Loss) Attributable to Extraction Oil & Gas, Inc.	28,148		61,845		(30,513)		18,698
Adjustments to reflect Series A Preferred Stock dividends and accretion of discount	(4,359		)	(4,197		)	(8,676		)	(8,357		)	Adjustments to reflect Series A Preferred Stock dividends and accretion of discount	(4,403)		(4,236)		(13,079)		(12,593)
Net Income (Loss) Attributable to Common Shareholders	34,988			4,651			(67,336		)	(51,504		)	Net Income (Loss) Attributable to Common Shareholders	23,745		57,609		(43,592)		6,105
Income (Loss) Per Common Share (Note 10)													Income (Loss) Per Common Share (Note 10)
Basic and diluted	$	0.22		$	0.03		$	(0.41	)	$	(0.29	)	Basic and diluted	$	0.17	$	0.33	$	(0.28)	$	0.03
Weighted Average Common Shares Outstanding													Weighted Average Common Shares Outstanding
Basic and diluted	159,410			175,762			165,025			174,992			Basic and diluted	137,789		175,814		155,847		175,269


	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, including payment of tax withholdings using withheld shares	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

Preferred Units issuance costs	—	—		—	—		—		—		—		10		10
Preferred Units commitment fees & dividends paid-in-kind	—	—		—	—		(4,098)		—		(4,098)		4,098		—
Stock-based compensation	—	—		—	—		14,957		—		14,957		—		14,957
Series A Preferred Stock dividends	—	—		—	—		(2,722)		—		(2,722)		—		(2,722)
Accretion of beneficial conversion feature on Series A Preferred Stock	—	—		—	—		(1,637)		—		(1,637)		—		(1,637)
Repurchase of common stock	—	(217)		21,685	(84,067)		—		—		(84,284)		—		(84,284)
Restricted stock issued, including payment of tax withholdings using withheld shares	108	—		—	—		(128)		—		(128)		—		(128)
Net income	—	—		—	—		—		43,444		43,444		—		43,444
Balance at June 30, 2019	176,588	$	1,384	34,052	$	(148,939)	$	2,164,295	$	(426,376)	$	1,590,364	$	155,945	$	1,746,309
Preferred Units issued	—	—		—	—		—		—		—		99,000		99,000
Preferred Units issuance costs	—	—		—	—		—		—		—		(2,500)		(2,500)
Preferred Units commitment fees & dividends paid-in-kind	—	—		—	—		(5,776)		—		(5,776)		5,776		—
Stock-based compensation	—	—		—	—		11,387		—		11,387		—		11,387
Series A Preferred Stock dividends	—	—		—	—		(2,721)		—		(2,721)		—		(2,721)
Accretion of beneficial conversion feature on Series A Preferred Stock	—	—		—	—		(1,682)		—		(1,682)		—		(1,682)
Repurchase of common stock	—	(48)		4,807	(21,199)		—		—		(21,247)		—		(21,247)
Restricted stock issued, including payment of tax withholdings using withheld shares	344	—		—	—		(582)		—		(582)		—		(582)
Net income	—	—		—	—		—		33,924		33,924		—		33,924
Balance at September 30, 2019	176,932	$	1,336	38,859	$	(170,138)	$	2,164,921	$	(392,452)	$	1,603,667	$	258,221	$	1,861,888



Supplemental cash flow information:
Property and equipment included in accounts payable and accrued liabilities	$	223,527	$	197,577
Cash paid for interest	$	45,648	$	41,607
Issuance of promissory note to unconsolidated subsidiary	$	—	$	35,329
Extinguishment of promissory note in exchange for equity with unconsolidated subsidiary	$	—	$	(35,329	)
Accretion of beneficial conversion feature of Series A Preferred Stock	$	3,233	$	2,914
Preferred Units commitment fees and dividends paid-in-kind	$	8,073	$	—


	Classification	As of September 30, 2019
Operating Leases
Operating lease right-of-use assets	Other non-current assets	$	20,470
Operating lease obligation - short-term	Accounts payable and accrued liabilities	9,236
Operating lease obligation - long-term	Other non-current liabilities	16,827
Total operating lease liabilities		$	26,063

Weighted Average Remaining Lease Term in Years
Operating leases		5.8
Weighted Average Discount Rate
Operating leases		4.7		%



	Classification	As of June 30, 2019
Operating Leases
Operating lease right-of-use assets	Other non-current assets	$	23,025
Current operating lease liabilities	Accounts payable and accrued liabilities	10,292
Non-current operating lease liabilities	Other non-current liabilities	18,442
Total operating lease liabilities		$	28,734

Weighted Average Remaining Lease Term in Years
Operating Leases		5.7
Weighted Average Discount Rate
Operating Leases		4.7		%



	June 30, 2019			December 31, 2018
Credit facility due August 16, 2022 (or an earlier time as set forth in the credit facility)	$	480,000		$	285,000
2024 Senior Notes due May 15, 2024	400,000			400,000
2026 Senior Notes due February 1, 2026	700,189			750,000
Unamortized debt issuance costs on Senior Notes	(15,522		)	(17,341		)
Total long-term debt	1,564,667			1,417,659
Less: current portion of long-term debt	—			—
Total long-term debt, net of current portion	$	1,564,667		$	1,417,659



	For the Six Months Ended June 30, 2019
Balance beginning of period	$	69,791
Liabilities incurred or acquired	244
Liabilities settled	(9,438		)
Revisions in estimated cash flows	26,596
Accretion expense	2,307
Balance end of period	$	89,500



(Registrant’s telephone number, including area code)



	Fair Value Measurements at June 30, 2019 Using
	Level 1		Level 2		Level 3			Total
Financial Assets:
Commodity derivative assets	$	—	$	39,630	$	—		$	39,630
Financial Liabilities:							��
Commodity derivative liabilities	$	—	$	3,675	$	—		$	3,675



	Fair Value Measurements at December 31, 2018 Using
	Level 1		Level 2		Level 3		Total
Financial Assets:
Commodity derivative assets	$	—	$	57,339	$	—	$	57,339
Financial Liabilities:
Commodity derivative liabilities	$	—	$	196	$	—	$	196


	Fair Value Measurement at September 30, 2019
	Level 1		Level 2		Level 3		Total
Financial Assets:
Commodity derivative assets	$	—	$	108,000	$	—	$	108,000
Financial Liabilities:
Commodity derivative liabilities	$	—	$	191	$	—	$	191


	Fair Value Measurement at December 31, 2018
	Level 1		Level 2		Level 3		Total
Financial Assets:
Commodity derivative assets	$	—	$	57,339	$	—	$	57,339
Financial Liabilities:
Commodity derivative liabilities	$	—	$	196	$	—	$	196


	At September 30, 2019						At December 31, 2018
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Credit Facility	$	550,000	$	550,000	$	285,000	$	285,000
2024 Senior Notes⁽¹⁾	$	394,577	$	262,000	$	393,866	$	330,000
2026 Senior Notes⁽²⁾	$	690,640	$	428,865	$	738,793	$	558,750



	At June 30, 2019				At December 31, 2018
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Credit Facility	$	480,000	$	480,000	$	285,000	$	285,000
2024 Senior Notes⁽¹⁾	$	394,336	$	343,000	$	393,866	$	330,000
2026 Senior Notes⁽²⁾	$	690,331	$	561,902	$	738,793	$	558,750


~~(1)~~	~~The carrying amount of the 2024 Senior Notes includes unamortized debt issuance costs of $5.7 million and $6.1 million as of June 30, 2019 and December 31, 2018, respectively.~~


~~(2)~~	The carrying amount of the 2026 Senior Notes includes unamortized debt issuance costs of $9.9 million and $11.2 million unamortized debt issuance costs as of June 30, 2019 and December 31, 2018, respectively.


	Number of Shares	Weighted Average Grant Date Fair Value
Non-vested RSUs at January 1, 2019	3,102,335	$	16.91
Granted	1,901,418	$	4.76
Forfeited	(280,029)	$	12.91
Vested	(1,011,340)	$	15.33
Non-vested RSUs at September 30, 2019	3,712,384	$	11.42


	Number of Shares ⁽¹⁾	Weighted Average Grant Date Fair Value
Non-vested PSAs at January 1, 2019	2,794,083	$	9.00
Granted	1,646,218	$	5.44
Forfeited	—	$	—
Vested	—	$	—
Non-vested PSAs at September 30, 2019	4,440,301	$	7.68


~~(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 grants, depending on the level of satisfaction of the vesting condition.


	Number of Options	Weighted Average Exercise Price
Non-vested Stock Options at January 1, 2019	1,748,148	$	18.50
Granted	—	$	—
Forfeited	—	$	—
Vested	(543,977)	$	18.72
Non-vested Stock Options at September 30, 2019	1,204,171	$	18.41


	Number of Shares	Weighted Average Grant Date Fair Value
Non-vested Incentive RSUs at January 1, 2019	476,000	$	20.45
Granted	—	$	—
Forfeited	—	$	—
Vested	(476,000)	$	20.45
Non-vested Incentive RSUs at September 30, 2019	—	$	—


	Operating Leases
2019 - remaining	$	2,956
2020	8,675
2021	3,340
2022	2,211
2023	2,246
Thereafter	10,573
Total lease payments	30,001
Less imputed interest ⁽¹⁾	(3,938)
Present value of lease liabilities ⁽²⁾	$	26,063



	Operating Leases
2019 - remaining	$	6,028
2020	8,630
2021	3,302
2022	2,196
2023	2,246
Thereafter	10,574
Total lease payments	32,976
Less imputed interest ⁽¹⁾	(4,242		)
Present value of lease liabilities ⁽²⁾	$	28,734


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


~~(2)~~	Of the total present value of lease liabilities, $10.3 million was recorded in "Accounts payable and accrued liabilities" and$18.4 million was recorded in "Other non-current liabilities" on the condensed consolidated balance sheets.


	Operating Leases
2019 - remaining	$	12,713
2020	3,371
2021	3,385
2022	3,360
2023	3,411
Thereafter	15,719
Total lease payments	$	41,959


	Oil (MBbl)	Gas (MMcf)	Total (MBOE)		Oil (MBbl)	Gas (MMcf)	Total (MBOE)
2019 - Remaining	4,048	5,185	4,912	2019 - Remaining	2,024	5,185	2,888
2020	8,935	33,550	14,527	2020	8,935	33,550	14,527
2021	10,349	46,540	18,106	2021	10,349	46,540	18,106
2022	9,128	49,758	17,421	2022	9,128	49,758	17,421
2023	9,490	41,850	16,465	2023	9,490	41,850	16,465
Thereafter	38,824	74,420	51,227	Thereafter	38,824	74,420	51,227
Total	80,774	251,303	122,658	Total	78,750	251,303	120,634


	For the Three Months Ended September 30, 2019
	Exploration and Production		Gathering and Facilities		Elimination of Intersegment Transactions		Consolidated Total
	As restated						As restated
Revenues:
Revenues from external customers	$	176,942	$	—	$	—	$	176,942
Intersegment revenues	—		—		—		—
Total Revenues	$	176,942	$	—	$	—	$	176,942

Operating Expenses and Other Income (Expense):
Depletion, depreciation, amortization and accretion	$	(114,971)	$	(25)	$	—	$	(114,996)
Interest income	114		355		—		469
Interest expense	(23,224)		—		—		(23,224)
Earnings in unconsolidated subsidiaries	—		640		—		640
Subtotal Operating Expenses and Other Income (Expense):	$	(138,081)	$	970	$	—	$	(137,111)

Segment Assets	$	4,046,862	$	395,224	$	(619)	$	4,441,467
Capital Expenditures	$	134,998	$	65,098	$	—	$	200,096
Investment in Equity Method Investees	$	—	$	35,992	$	—	$	35,992
Segment EBITDAX	$	138,491	$	(622)	$	—	$	137,869