Halcón Resources Corporation
(Exact name of registrant as specified in its charter)

1000 Louisiana Street, Suite 6600, Houston, TX 77002
(Address of principal executive offices)

(832) 538-0300
(Registrant's telephone number, including area code)
(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes ý No o

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

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

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

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

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

At November 7, 2019, 16,203,940 shares of the Registrant's Common Stock were outstanding.

This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of the federal securities laws. All statements, other than statements of historical facts, are forward-looking statements, and include statements concerning, among other things, planned capital expenditures, potential increases in oil and natural gas production, potential costs to be incurred, future cash flows and borrowings, our financial position, business strategy and other plans and objectives for future operations. Forward-looking statements may sometimes be identified by their use of terms and phrases such as "may," "expect," "estimate," "project," "plan," "objective," "believe," "predict," "intend," "achievable," "anticipate," "will," "continue," "potential," "should," "could" and similar terms and phrases. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties. Actual results could differ materially from those anticipated in these forward-looking statements. Readers should consider carefully the risks described under the "Risk Factors" section of our previously filed Annual Report on Form 10-K for the fiscal year ended December 31, 2018, as well as the other disclosures contained herein and therein, which describe factors that could cause our actual results to differ from those anticipated in the forward-looking statements, including, but not limited to, the following factors:

All forward-looking statements are expressly qualified in their entirety by the cautionary statements in this paragraph and elsewhere in this document. Other than as required under the securities laws, 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.

	Three Months Ended September 30,						Nine Months Ended September 30,

	2019			2018			2019			2018
Operating revenues:
Oil, natural gas and natural gas liquids sales:
Oil	$	46,275		$	53,918		$	145,024		$	145,743
Natural gas		301			1,407			107			5,286
Natural gas liquids		3,987			5,920			13,229			14,623

Total oil, natural gas and natural gas liquids sales		50,563			61,245			158,360			165,652
Other		246			350			743			613

Total operating revenues		50,809			61,595			159,103			166,265

Operating expenses:
Production:
Lease operating		11,958			5,275			39,617			15,504
Workover and other		1,566			1,478			5,580			4,795
Taxes other than income		3,012			3,557			9,213			9,812
Gathering and other		10,147			18,404			36,057			30,782
Restructuring		3,223			—			15,148			128
General and administrative		19,423			19,731			36,550			49,196
Depletion, depreciation and accretion		20,512			20,310			90,912			52,397
Full cost ceiling impairment		45,568			—			985,190			—
(Gain) loss on sale of oil and natural gas properties		—			1,331			—			7,235
(Gain) loss on sale of Water Assets		(164	)		—			3,618			—

Total operating expenses		115,245			70,086			1,221,885			169,849

Income (loss) from operations		(64,436	)		(8,491	)		(1,062,782	)		(3,584	)
Other income (expenses):
Net gain (loss) on derivative contracts		13,457			(60,406	)		(34,332	)		(66,603	)
Interest expense and other		(10,547	)		(12,940	)		(37,606	)		(30,522	)
Reorganization items		(1,758	)		—			(1,758	)		—

Total other income (expenses)		1,152			(73,346	)		(73,696	)		(97,125	)

Income (loss) before income taxes		(63,284	)		(81,837	)		(1,136,478	)		(100,709	)
Income tax benefit (provision)		—			—			95,791			—

Net income (loss)	$	(63,284	)	$	(81,837	)	$	(1,040,687	)	$	(100,709	)



Net income (loss) per share of common stock:
Basic	$	(0.40	)	$	(0.52	)	$	(6.55	)	$	(0.64	)



Diluted	$	(0.40	)	$	(0.52	)	$	(6.55	)	$	(0.64	)



Weighted average common shares outstanding:
Basic		159,143			158,011			158,916			156,628



Diluted		159,143			158,011			158,916			156,628

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

	September 30, 2019			December 31, 2018

Current assets:
Cash and cash equivalents	$	17,009		$	46,866
Accounts receivable		37,826			35,718
Receivables from derivative contracts		15,310			57,280
Prepaids and other		14,642			4,788

Total current assets		84,787			144,652

Oil and natural gas properties (full cost method):
Evaluated		2,155,288			1,470,509
Unevaluated		438,365			971,918

Gross oil and natural gas properties		2,593,653			2,442,427
Less—accumulated depletion		(1,709,719	)		(639,951	)

Net oil and natural gas properties		883,934			1,802,476

Other operating property and equipment:
Other operating property and equipment		203,373			130,251
Less—accumulated depreciation		(14,416	)		(8,388	)

Net other operating property and equipment		188,957			121,863

Other noncurrent assets:
Receivables from derivative contracts		4,120			12,437
Operating lease right of use assets		3,694			—
Funds in escrow and other		1,138			2,181

Total assets	$	1,166,630		$	2,083,609



Current liabilities:
Accounts payable and accrued liabilities	$	112,578		$	157,848
Liabilities from derivative contracts		6,829			3,768
Current portion of long-term debt		258,234			—
Operating lease liabilities		1,337			—
Asset retirement obligations		—			126

Total current liabilities		378,978			161,742

Long-term debt, net		—			613,105
Liabilities subject to compromise		625,005			—
Other noncurrent liabilities:
Liabilities from derivative contracts		1,625			9,139
Asset retirement obligations		10,153			6,788
Operating lease liabilities		2,438			—
Deferred income taxes		—			95,791
Commitments and contingencies (Note 11)
Stockholders' equity:
Common stock: 1,000,000,000 shares of $0.0001 par value authorized; 162,217,095 and 160,612,852 shares issued and outstanding as of September 30, 2019 and December 31, 2018, respectively		16			16
Additional paid-in capital		1,087,441			1,095,367
Retained earnings (accumulated deficit)		(939,026	)		101,661

Total stockholders' equity		148,431			1,197,044

Total liabilities and stockholders' equity	$	1,166,630		$	2,083,609

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

	Common Stock								Retained Earnings (Accumulated Deficit)

	Common Stock					Additional Paid-In Capital						Stockholders' Equity
	Shares			Amount		Additional Paid-In Capital						Stockholders' Equity
Balances at December 31, 2018		160,613		$	16	$	1,095,367		$	101,661		$	1,197,044
Net income (loss)		—			—		—			(336,559	)		(336,559	)
Long-term incentive plan grants		4,153			—		—			—			—
Long-term incentive plan forfeitures		(193	)		—		—			—			—
Reduction in shares to cover
individuals' tax withholding		(253	)		—		(406	)		—			(406	)
Stock-based compensation		—			—		(6,416	)		—			(6,416	)

Balances at March 31, 2019		164,320			16		1,088,545			(234,898	)		853,663
Net income (loss)		—			—		—			(640,844	)		(640,844	)
Long-term incentive plan grants		11			—		—			—			—
Long-term incentive plan forfeitures		(166	)		—		—			—			—
Reduction in shares to cover
individuals' tax withholding		(42	)		—		(20	)		—			(20	)
Stock-based compensation		—			—		1,358			—			1,358

Balances at June 30, 2019		164,123			16		1,089,883			(875,742	)		214,157
Net income (loss)		—			—		—			(63,284	)		(63,284	)
Long-term incentive plan forfeitures		(1,742	)		—		—			—			—
Reduction in shares to cover
individuals' tax withholding		(164	)		—		(14	)		—			(14	)
Stock-based compensation		—			—		(2,428	)		—			(2,428	)

Balances at September 30, 2019		162,217		$	16	$	1,087,441		$	(939,026	)	$	148,431

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

HALCÓN RESOURCES CORPORATION (DEBTOR-IN-POSSESSION)

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Unaudited)

(In thousands)

	Common Stock								Retained Earnings (Accumulated Deficit)

	Common Stock					Additional Paid-In Capital						Stockholders' Equity
	Shares			Amount		Additional Paid-In Capital						Stockholders' Equity
Balances at December 31, 2017		149,379		$	15	$	1,016,281		$	55,702		$	1,071,998
Net income (loss)		—			—		—			(2,598	)		(2,598	)
Common stock issuance		9,200			1		63,479			—			63,480
Offering costs		—			—		(3,044	)		—			(3,044	)
Stock option exercises		42			—		323			—			323
Long-term incentive plan grants		1,922			—		—			—			—
Long-term incentive plan forfeitures		(74	)		—		—			—			—
Stock-based compensation		—			—		4,066			—			4,066

Balances at March 31, 2018		160,469			16		1,081,105			53,104			1,134,225
Net income (loss)		—			—		—			(16,274	)		(16,274	)
Long-term incentive plan grants		320			—		—			—			—
Long-term incentive plan forfeitures		(136	)		—		—			—			—
Reduction in shares to cover
individuals' tax withholding		(53	)		—		(262	)		—			(262	)
Stock-based compensation		—			—		5,194			—			5,194

Balances at June 30, 2018		160,600			16		1,086,037			36,830			1,122,883
Net income (loss)		—			—		—			(81,837	)		(81,837	)
Long-term incentive plan grants		84			—		—			—			—
Long-term incentive plan forfeitures		(8	)		—		—			—			—
Stock-based compensation		—			—		5,404			—			5,404

Balances at September 30, 2018		160,676			16		1,091,441			(45,007	)		1,046,450
Net income (loss)		—			—		—			146,668			146,668
Long-term incentive plan forfeitures		(43	)		—		—			—			—
Reduction in shares to cover
individuals' tax withholding		(20	)		—		(39	)		—			(39	)
Stock-based compensation		—			—		3,965			—			3,965

Balances at December 31, 2018		160,613		$	16	$	1,095,367		$	101,661		$	1,197,044

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

	Nine Months Ended September 30,

	2019			2018
Cash flows from operating activities:
Net income (loss)	$	(1,040,687	)	$	(100,709	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depletion, depreciation and accretion		90,912			52,397
Full cost ceiling impairment		985,190			—
(Gain) loss on sale of oil and natural gas properties		—			7,235
(Gain) loss on sale of Water Assets		3,618			—
Deferred income tax provision (benefit)		(95,791	)		—
Stock-based compensation, net		(8,035	)		12,241
Unrealized loss (gain) on derivative contracts		45,834			77,524
Amortization and write-off of deferred loan costs		1,859			1,022
Amortization of discount and premium		134			235
Reorganization items		(283	)		—
Other income (expense)		535			1,314
Change in assets and liabilities:
Accounts receivable		3,781			(7,498	)
Prepaids and other		(9,854	)		(341	)
Accounts payable and accrued liabilities		(10,446	)		(6,711	)

Net cash provided by (used in) operating activities		(33,233	)		36,709

Cash flows from investing activities:
Oil and natural gas capital expenditures		(167,235	)		(369,304	)
Proceeds received from sale of oil and natural gas properties		1,247			1,647
Acquisition of oil and natural gas properties		(2,809	)		(333,470	)
Other operating property and equipment capital expenditures		(85,613	)		(79,389	)
Proceeds received from sale of other operating property and equipment		—			2,236
Funds held in escrow and other		(7	)		153

Net cash provided by (used in) investing activities		(254,417	)		(778,127	)

Cash flows from financing activities:
Proceeds from borrowings		315,234			293,000
Repayments of borrowings		(57,000	)		(32,000	)
Debt issuance costs		—			(4,013	)
Common stock issued		—			63,480
Offering costs and other		(441	)		(2,983	)

Net cash provided by (used in) financing activities		257,793			317,484

Net increase (decrease) in cash and cash equivalents		(29,857	)		(423,934	)
Cash and cash equivalents at beginning of period		46,866			424,071

Cash and cash equivalents at end of period	$	17,009		$	137



Supplemental cash flow information:
Cash paid for reorganization items	$	2,041		$	—
Disclosure of non-cash investing and financing activities:
Asset retirement obligations	$	2,932		$	2,519

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

Halcón Resources Corporation (Halcón or the Company) is an independent energy company focused on the acquisition, production, exploration and development of onshore liquids-rich oil and natural gas assets in the United States. The unaudited condensed consolidated financial statements include the accounts of all majority-owned, controlled subsidiaries. The Company operates in one segment which focuses on oil and natural gas acquisition, production, exploration and development. Allocation of capital is made across the Company's entire portfolio without regard to operating area. All intercompany accounts and transactions have been eliminated. These unaudited condensed consolidated financial statements reflect, in the opinion of the Company's management, all adjustments, consisting of normal and recurring adjustments, necessary to present fairly the financial position as of, and the results of operations for, the periods presented. During interim periods, Halcón follows the accounting policies disclosed in its 2018 Annual Report on Form 10-K, as filed with the United States Securities and Exchange Commission (SEC) on March 12, 2019. Please refer to the notes in the 2018 Annual Report on Form 10-K when reviewing interim financial results.

The preparation of the Company's unaudited condensed consolidated financial statements in conformity with accounting principles generally accepted in the United States requires the Company's management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the unaudited condensed consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Estimates and assumptions that, in the opinion of the Company's management, are significant include oil and natural gas revenue accruals, capital and operating expense accruals, oil and natural gas reserves, depletion relating to oil and natural gas properties, asset retirement obligations, fair value estimates, and income taxes. The Company bases its estimates and judgments on historical experience and on various other assumptions and information believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be predicted with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as the Company's operating environment changes. Actual results may differ from the estimates and assumptions used in the preparation of the Company's unaudited condensed consolidated financial statements.

Interim period results are not necessarily indicative of results of operations or cash flows for the full year and accordingly, certain information normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States, has been condensed or omitted. The Company has evaluated events or transactions through the date of issuance of these unaudited condensed consolidated financial statements.

On August 7, 2019 (the Petition Date), the Company and its subsidiaries (the Halcón Entities) filed voluntary petitions for relief under chapter 11 of the United States Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of Texas (the Bankruptcy Court) to pursue a prepackaged plan of reorganization (the Plan). The Halcón Entities' chapter 11 proceedings were administered under the caption In re Halcón Resources Corporation, et al. (Case No. 19-34446). On September 24,

2019, the Bankruptcy Court entered an order confirming the Plan and on October 8, 2019, the Plan became effective (the Effective Date) and the Halcón Entities emerged from chapter 11 bankruptcy. Although the Company is no longer a debtor-in-possession, the Company was a debtor-in-possession for the three months ended September 30, 2019. As such, the Company's chapter 11 proceedings and related matters have been summarized below. See Note 2, "Reorganization," for further details on the Company's chapter 11 bankruptcy and the Plan and Note 15, "Subsequent Events" for further details on emergence.

The Company has applied Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 852, Reorganizations (ASC 852), in the preparation of these unaudited condensed consolidated financial statements. For periods subsequent to the chapter 11 filings, ASC 852 requires the financial statements to distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain expenses, realized gains and losses and provisions for losses that are realized or incurred during the chapter 11 proceedings, including adjustments to the carrying value of certain indebtedness are recorded as "Reorganization items" in the unaudited condensed consolidated statements of operations. In addition, prepetition obligations that may be impacted by the chapter 11 proceedings have been classified as "Liabilities subject to compromise" on the unaudited condensed consolidated balance sheet as of September 30, 2019.

The accompanying unaudited condensed consolidated balance sheet as of September 30, 2019 includes amounts classified as liabilities subject to compromise, which represent liabilities that were allowed as claims by the Bankruptcy Court in the chapter 11 proceedings. These amounts represent the Company's obligations that were adjudicated in connection with the chapter 11 proceedings.

The following table summarizes the components of liabilities subject to compromise included on the unaudited condensed consolidated balance sheet as of September 30, 2019 (in thousands):

As of September 30, 2019, the principal and accrued interest associated with the Senior Credit Agreement and the Junior Secured Debtor-In-Possession Credit Agreement (the DIP Credit Agreement) were not classified as liabilities subject to compromise as a result of the adequate protection approved by the Bankruptcy Court. See Note 7, "Debt," for more information.

The Company has incurred significant expenses associated with the Chapter 11 proceedings subsequent to the Petition Date as a direct result of the Plan. These costs, which are expensed when

incurred, are recorded in "Reorganization items" in the Company's unaudited condensed consolidated statements of operations. The following table summarizes the net reorganization items (in thousands):

The Company has discontinued recording interest on debt instruments classified as liabilities subject to compromise as of the Petition Date. The contractual interest expense on liabilities subject to compromise not accrued or recorded in the unaudited condensed consolidated statement of operations was approximately $6.2 million, representing interest expense from the Petition Date through September 30, 2019.

The Company considers all highly liquid short-term investments with a maturity of three months or less at the time of purchase to be cash equivalents. These investments are carried at cost, which approximates fair value.

The Company's accounts receivable are primarily receivables from joint interest owners and oil and natural gas purchasers. Accounts receivable are recorded at the amount due, less an allowance for doubtful accounts, when applicable. The Company establishes provisions for losses on accounts receivable if it determines that collection of all or part of the outstanding balance is doubtful. The Company regularly reviews collectability and establishes or adjusts the allowance for doubtful accounts as necessary using the specific identification method. As of September 30, 2019 and December 31, 2018, allowances for doubtful accounts were approximately $0.1 million and $0.2 million, respectively.

Other operating property and equipment additions are recorded at cost. Depreciation is calculated using the straight-line method over the following estimated useful lives: oil and gas gathering systems, thirty years; gas treating systems and buildings, twenty years; automobiles and computers, three years; computer software, fixtures, furniture and equipment, the lesser of lease term or five years; trailers, seven years; heavy equipment, eight to ten years and leasehold improvements, lease term. Upon disposition, the cost and accumulated depreciation are removed and any gains or losses are reflected in current operations. Maintenance and repair costs are charged to operating expense as incurred. Material expenditures which increase the life or productive capacity of an asset are capitalized and depreciated over the estimated remaining useful life of the asset.

The Company reviews its other operating property and equipment for impairment in accordance with ASC 360, Property, Plant, and Equipment (ASC 360). ASC 360 requires the Company to evaluate other operating property and equipment for impairment as events occur or circumstances change that would more likely than not reduce the fair value below the carrying amount. If the carrying amount is not recoverable from its undiscounted cash flows, then the Company would recognize an impairment loss for the difference between the carrying amount and the current fair value. Further, the Company evaluates the remaining useful lives of its other operating property and equipment at each reporting period to determine whether events and circumstances warrant a revision to the remaining depreciation periods.

Effective January 1, 2019, the Company accounts for leases in accordance with ASC 842, Leases (ASC 842). The Company determines if an arrangement is a lease at contract inception. A lease exists when a contract conveys to the customer the right to control the use of identified asset for a period of time in exchange for consideration. The definition of a lease embodies two conditions: (1) there is an identified asset in the contract that is land or a depreciable asset, and (2) the customer has the right to control the use of the identified asset.

The Company leases equipment and office space pursuant to net operating leases. Operating leases where the Company is the lessee are included in "Operating lease right of use assets" and "Operating lease liabilities" on the unaudited condensed consolidated balance sheets. The lease liabilities are initially and subsequently measured at the present value of the unpaid lease payments at the lease commencement date.

Key estimates and judgments include how the Company determined (1) the discount rate used to discount the unpaid lease payments to present value, (2) lease term and (3) lease payments. ASC 842 requires a lessee to discount its unpaid lease payments using the interest rate implicit in the lease or, if that rate cannot be readily determined, its incremental borrowing rate. As most of the Company's leases do not provide an implicit rate, the Company uses its incremental borrowing rate based on the information available at the commencement date to determine the present value of lease payments. The incremental borrowing rate for a lease is the rate of interest the Company would have to pay on a collateralized basis to borrow an amount equal to the lease payments under similar terms. Additionally, the Company applies a portfolio approach to determine the discount rate (the incremental borrowing rate for leases with similar characteristics). The Company uses the implicit rate when readily determinable. The lease term includes the noncancellable period of the lease plus any additional periods covered by either a lessee option to extend (or not to terminate) the lease that the lessee is reasonably certain to exercise, or an option to extend (or not to terminate) the lease controlled by the lessor. Lease payments included in the measurement of the lease asset or liability comprise the following, when applicable: fixed payments (including in-substance fixed payments), variable payments that depend on index or rate, and the exercise price of a lessee option to purchase the underlying asset if the lessee is reasonably certain to exercise.

The right of use asset is initially measured at cost, which comprises the initial amount of the lease liability adjusted for lease payments made at or before the lease commencement date, plus any initial direct costs incurred less any lease incentives received. For the Company's operating leases, the right of use asset is subsequently measured throughout the lease term at the carrying amount of the lease

liability, plus initial direct costs, plus (minus) any prepaid (accrued) lease payments, less the unamortized balance of lease incentives received. Lease expense for lease payments is recognized on a straight-line basis over the lease term.

Variable lease payments associated with the Company's leases are recognized when the event, activity, or circumstance in the lease agreement on which those payments are assessed occurs. Variable lease payments, when applicable, are presented as "Gathering and other" or "General and administrative" in the unaudited condensed consolidated statements of operations in the same line item as the expense arising from the fixed lease payments on the operating leases.

The Company has lease agreements which include lease and nonlease components and the Company has elected to combine lease and nonlease components, when fixed, for all lease contracts. Nonlease components include common area maintenance charges on office leases and, when applicable, services associated with equipment leases. The Company determines whether the lease or nonlease component is the predominant component on a case-by-case basis.

The Company reviews its right of use assets for impairment in accordance with ASC 360. ASC 360 requires the Company to evaluate right of use assets for impairment as events occur or circumstances change that would more likely than not reduce the fair value below the carrying amount. If the carrying amount is not recoverable from its undiscounted cash flows, then the Company would recognize an impairment loss for the difference between the carrying amount and the current fair value.

The Company monitors for events or changes in circumstances that would require a reassessment of a lease. When a reassessment results in the remeasurement of a lease liability, an adjustment is made to the carrying amount of the corresponding right of use asset unless doing so would reduce the carrying amount of the right of use asset to an amount less than zero. In that case, the amount of the adjustment that would result in a negative right of use asset balance is recorded in the unaudited condensed consolidated statements of operations.

The Company elected not to recognize right of use assets and lease liabilities for all short-term leases that have a lease term of 12 months or less. The Company recognizes the lease payments associated with its short-term leases as an expense on a straight-line basis over the lease term. Variable lease payments associated with these leases are recognized and presented in the same manner as for all other leases.

During the nine months ended September 30, 2019, senior executives of the Company resigned from their positions. These were considered terminations without cause under their respective employment agreements, which entitled them to certain benefits. Additionally during the period, the Company made the decision to consolidate into one corporate office located in Houston, Texas in an effort to improve efficiencies and go forward costs. The transition includes both severance and relocation costs as well as incremental costs associated with hiring new employees to replace key positions. Consequently, for the three and nine months ended September 30, 2019, the Company incurred $3.2 million and approximately $15.1 million, respectively, in costs which were recorded in "Restructuring" on the unaudited condensed consolidated statements of operations.

For the three and nine months ended September 30, 2019, the Company utilized the discrete effective tax rate method, as allowed by ASC 740, Income Taxes, to calculate its interim income tax provision. The discrete method is applied when it is not possible to reliably estimate the annual effective tax rate. The Company believes the use of the discrete method is more appropriate than the annual effective tax rate method at this time because of the uncertainties caused by the Company's filing of a voluntary petition for relief under chapter 11 of the United States Bankruptcy Code. The uncertainties include, but are not limited to, the 1) level of capital spending in future periods and its impact on production and future ceiling impairment analysis, 2) the expected allocation of income for the year between the pre- and post-emergence periods, and 3) the expected level of interest expense and restructuring expenses for the year.

On July 27, 2018, a subsidiary of the Company entered into a crude oil gathering agreement with SCM Crude, LLC (SCM) pursuant to which the Company agreed to dedicate, for a term of 15 years, production of crude oil from its currently owned, or later acquired acreage in designated areas in Ward and Winkler Counties, Texas (excluding certain specific wells) for the receipt, gathering and transportation on a gathering system to be designed, engineered and constructed by SCM. In the fourth quarter of 2018, the Company began selling its crude oil to SCM while the gathering system was under construction. The gathering system was completed and placed into service in March 2019. For the three and nine months ended September 30, 2019, the Company recorded revenue of $24.7 million and $101.6 million, respectively, from SCM under the crude oil gathering agreement and had no receivables outstanding from SCM.

Certain funds under the control of Ares Management LLC (Ares) are the majority owners and controlling parties of SCM. Ares also controls other funds which owned in excess of ten percent (10%) of the common stock of the Company prior to the Effective Date of the Plan. No Ares fund that is a stockholder of the Company has an interest in SCM but one of the Company's former directors, who is employed by Ares, also serves on the board of directors of SCM's parent company.

On November 16, 2017, a subsidiary of the Company entered into a gas purchase and processing agreement with Salt Creek Midstream, LLC (Salt Creek) pursuant to which the Company agreed to dedicate, for a term of 15 years, all production from its acreage in Ward County, Texas (that is not otherwise previously dedicated) and certain sections in Winkler County, Texas to a natural gas gathering pipeline and processing facilities to be constructed by Salt Creek. The facilities were completed and placed into service in May 2018. For the three and nine months ended September 30, 2019, the Company recorded revenue of $2.9 million and $6.0 million, respectively, from Salt Creek under the gas purchase and processing agreement. As of September 30, 2019, the Company recorded a $1.5 million receivable from Salt Creek for its natural gas sales.

Certain funds under the control of Ares are the majority owners and controlling parties of Salt Creek. Ares also controls other funds which owned in excess of ten percent (10%) of the stock of the

Company prior to the Effective Date of the Plan. No Ares fund that is a stockholder of the Company has an interest in Salt Creek but one of the Company's former directors, who is employed by Ares, also serves on the board of directors of Salt Creek.

In February 2019, the Company entered into an agreement with Cima Inspection LLC (Cima), a company specializing in advanced, non-destructive methods of testing pipes and tubing, pursuant to which Cima will inspect various Company gathering and transportation assets. One of the Company's former directors (as of the Effective Date of the Plan) owns a minority interest in Cima and currently serves as its chief executive officer. For the three and nine months ended September 30, 2019, the Company incurred charges of approximately $0.3 million and $0.9 million, respectively, for services provided by Cima. As of September 30, 2019, the Company recorded a less than $0.1 million payable to Cima.

In the ordinary course of business, Halcón occasionally chartered a private aircraft for business use. Floyd C. Wilson, Halcón's former Chairman, Chief Executive Officer and President, indirectly owns an aircraft which the Company chartered from time to time. During 2018, fees for the use of Mr. Wilson's aircraft by the Company were based upon comparable costs that the Company would have incurred in chartering the same type and size of aircraft from an independent third party utilizing data from several independent third party aircraft leasing companies. The terms for this use were evaluated and approved by the Audit Committee, and subsequently by the disinterested members of the Company's board upon the recommendation of the Audit Committee, in accordance with the Company's procedures for the review and approval of transactions with related parties. In the first quarter of 2019, the Company terminated all charter arrangements with Mr. Wilson relating to the use of his aircraft. During the nine months ended September 30, 2019, the Company paid approximately $0.2 million, related to use of the aircraft indirectly owned by Mr. Wilson during 2018.

In February 2016, the FASB issued Accounting Standards Update (ASU) No. 2016-02, Leases (Topic 842) (ASU 2016-02). For public business entities, ASU 2016-02 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018. The FASB issued ASU 2016-02 to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The Company adopted ASU 2016-02 effective January 1, 2019 using the modified retrospective approach as of the adoption date. See "Leases" above and Note 3, "Leases," below for further details.

On August 2, 2019, the Halcón Entities entered into a Restructuring Support Agreement (the Restructuring Support Agreement) with certain holders of the Company's 6.75% senior unsecured notes due 2025 (the Unsecured Senior Noteholders). On August 7, 2019, the Halcón Entities filed voluntary petitions for relief under chapter 11 of the United States Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of Texas to effect an accelerated prepackaged bankruptcy

restructuring as contemplated in the Restructuring Support Agreement. The Halcón Entities continued to operate its businesses as debtors-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the United States Bankruptcy Code and orders of the Bankruptcy Court. On September 24, 2019, the Bankruptcy Court entered an order confirming the Company's plan of reorganization and on October 8, 2019, the Halcón Entities emerged from chapter 11 bankruptcy. See Note 15, "Subsequent Events" for further details on emergence.

Pursuant to the terms of the Plan contemplated by the Restructuring Support Agreement, the Unsecured Senior Noteholders and other claim and interest holders received the following treatment in full and final satisfaction of their claims and interests:

Each of the foregoing percentages of equity in the reorganized Company were as of October 8, 2019 and are subject to dilution by New Common Shares issued in connection with (i) a management incentive plan, (ii) the Warrants (defined below), (iii) the Equity Rights Offerings (defined below), and (iv) the Backstop Commitment Premium (defined below).

As a component of the Restructuring Support Agreement (i) each Unsecured Senior Noteholder was offered the right to purchase its pro rata share of New Common Shares for an aggregate purchase price of $150,150,000 (the Senior Noteholder Rights Offering) and (ii) each existing common stockholder was offered (subject to the Existing Equity Cash Out) the right to purchase its pro rata share of New Common Shares for an aggregate purchase price of up to $14,850,000 (the Existing Equity Interests Rights Offering, and together with the Senior Noteholder Rights Offering, the Equity Rights Offerings), in each case, at a price per share equal to a 26% discount to the value of the New Common Shares based on an assumed total enterprise value of $425 million. Certain of the Unsecured Senior Noteholders backstopped the Senior Noteholder Rights Offering and received as consideration (the Backstop Commitment Premium) New Common Shares equal to 6% of the aggregate amount of the Senior Noteholder Rights Offering, subject to dilution by New Common Shares issued in connection with a management incentive plan and the Warrants. If the backstop agreement had been

terminated, the Company would have been obligated to a cash payment equal to 6% of the aggregate amount of the Senior Noteholder Rights Offering. The proceeds of the Equity Rights Offerings were used by the Company to (i) provide additional liquidity for working capital and general corporate purposes, (ii) pay all reasonable and documented restructuring expenses, and (iii) fund Plan distributions.

Under the Restructuring Support Agreement, each existing common stockholder (subject to the Existing Equity Cash Out) will be issued a series of warrants exercisable in cash for a three year period subsequent to the effective date of the Plan (Warrants). The Warrants were issued with strike prices based upon stipulated rate-of-return levels achieved by the Unsecured Senior Noteholders. The Warrants cumulatively represent 30% of the New Common Shares issued pursuant to the Plan.

On January 1, 2019, the Company adopted ASC 842 using the modified retrospective approach as of the adoption date. Reporting periods beginning after January 1, 2019 are presented under ASC 842, while prior period amounts are not adjusted and continue to be reported under the accounting standards in effect for those periods. The table below details the impact of adoption on the Company's unaudited condensed consolidated balance sheet as of January 1, 2019 (in thousands):

The Company elected the following practical expedients for transition to, and ongoing accounting under, ASC 842: i) the Company does not separate lease and non-lease components of a contract, ii) the Company does not reassess whether expired or existing contracts contain leases, nor does it reassess the lease classification for expired or existing leases and does not reassess whether previously capitalized initial direct costs would qualify for capitalization under ASC 842, iii) the Company applies a single discount rate to a portfolio of leases with reasonably similar characteristics and iv) the Company does not assess whether existing or expired land easements that were not previously accounted for as leases are or contain a lease under ASC 842.

The Company leases equipment and office space under operating leases. The operating leases have initial lease terms ranging from 1 to 5 years, some of which include options to extend or renew the

leases for one year. Payments due under the lease contracts include fixed payments plus, in some instances, variable payments. The table below summarizes the Company's leases for the nine months ended September 30, 2019 (in thousands, except years and discount rate):

	Nine Months Ended September 30, 2019

Lease cost
Operating lease costs	$	1,932
Short-term lease costs		12,262
Variable lease costs		1,210

Total lease costs	$	15,404



Other information
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases	$	1,936
Right-of-use assets obtained in exchange for new operating lease liabilities		5,462
Weighted-average remaining lease term—operating leases		3.7 years
Weighted-average discount rate—operating leases		4.83	%

Future minimum lease payments associated with the Company's non-cancellable operating leases for office space and equipment as of September 30, 2019, are presented in the table below (in thousands):

Prior to the adoption of ASC 842, future obligations, including variable nonlease components, associated with the Company's non-cancellable operating leases for office space and equipment as of December 31, 2018, are presented in the table below (in thousands):

Revenue is measured based on consideration specified in a contract with a customer and excludes amounts collected on behalf of third parties. Taxes assessed by a governmental authority that are both imposed on and concurrent with a specific revenue-producing transaction that are collected by the Company from a customer are excluded from revenue. Revenues from the sale of crude oil, natural gas and natural gas liquids are recognized, at a point in time, when a performance obligation is satisfied by the transfer of control of the commodity to the customer. Because the Company's performance obligations have been satisfied and an unconditional right to consideration exists as of the balance sheet date, the Company recognized amounts due from contracts with customers of $26.6 million and $26.4 million as of September 30, 2019 and December 31, 2018, respectively, as "Accounts receivable" on the unaudited condensed consolidated balance sheets.

Substantially all of the Company's revenues are derived from its single basin operations, the Delaware Basin in Pecos, Reeves, Ward and Winkler Counties, Texas. The following table disaggregates the Company's revenues by major product, in order to depict how the nature, timing, and uncertainty of revenue and cash flows are affected by economic factors in the Company's single basin operations, for the periods indicated (in thousands):

The Company generally markets its crude oil production directly to the customer using two methods. Under the first method, crude oil is sold at the wellhead at an index price adjusted for pricing differentials and other deductions. Revenue is recognized at the wellhead, where control of the crude oil transfers to the customer, at the net price received. Under the second method, crude oil is delivered to the customer at a contractual delivery point at which the customer takes custody, title and risk of loss of the product. The Company receives a specified index price from the customer, net of transportation costs and other market-related adjustments. Revenue is recognized when control of the crude oil transfers at the delivery point at the net price received.

Settlement statements for the Company's crude oil production are typically received within the month following the date of production and therefore the amount of production delivered to the customer and the price that will be received for that production are known at the time the revenue is recorded. Payment under the Company's crude oil contracts is typically due on or before the 20^th of the month following the delivery month.

The Company evaluates its natural gas gathering and processing arrangements in place with midstream companies to determine when control of the natural gas is transferred. Under contracts where it is determined that control of the natural gas transfers at the wellhead, any fees incurred to gather or process the unprocessed natural gas are a reduction of the sales price of unprocessed natural gas, and therefore revenues from such transactions are presented on a net basis. Under contracts where it is determined that control of the natural gas transfers at the tailgate of the midstream entity's processing plant, the Company is the principal and the midstream entity is the agent in the sale transaction with the third party purchaser of processed commodities. In these instances, revenues are presented on a gross basis for amounts expected to be received from the midstream company or third party purchasers through the gathering and treating process and presented as "Natural gas" or "Natural gas liquids" and any fees incurred to gather or process the natural gas are presented as "Gathering and other" on the unaudited condensed consolidated statements of operations.

Under certain contracts, the Company may elect to take its residue gas and/or natural gas liquids in-kind at the tailgate of the midstream entity's processing plant. The Company then sells the products to a customer at contractual delivery points at prices based on an index. In these instances, revenues are presented on a gross basis and any fees incurred to gather, process or transport the commodities are presented separately as "Gathering and other" on the unaudited condensed consolidated statement of operations.

Settlement statements for the Company's natural gas and natural gas liquids production are typically received 30 days after the date of production and therefore the Company estimates the amount of production delivered to the customer and the price that will be received for that production. Historically, differences between the Company's estimates and the actual revenue received have not been material. Payment under the Company's natural gas gathering and processing contracts is typically due on or before the fifth day of the second month following the delivery month.

On February 6, 2018, a wholly owned subsidiary of the Company entered into a Purchase and Sale Agreement (the Shell PSA) with SWEPI LP (Shell), an affiliate of Shell Oil Company, pursuant to which the Company purchased acreage and related assets in the Delaware Basin located in Ward County, Texas (the West Quito Draw Properties) for a total adjusted purchase price of $198.5 million. The effective date of the acquisition was February 1, 2018, and the Company closed the transaction on April 4, 2018. The Company funded the cash consideration for the acquisition of the West Quito Draw Properties with the net proceeds from the issuance of additional 6.75% senior notes due 2025 and common stock, which are discussed in Note 7, "Debt," and Note 12, "Stockholders' Equity," respectively.

On January 9, 2018, the Company purchased acreage in the Monument Draw area of the Delaware Basin, located in Ward and Winkler Counties, Texas (the Ward County Assets) that is prospective for the Wolfcamp and Bone Spring formations from a private company for $108.2 million in cash.

On December 20, 2018, the Company sold its water infrastructure assets located in the Delaware Basin (the Water Assets) to WaterBridge Resources LLC (the Purchaser) for a total adjusted purchase price of $210.9 million in cash (the Water Infrastructure Divestiture). The effective date of the transaction was October 1, 2018. Additional incentive payments of up to $25.0 million per year for the years from 2019 to 2023 were available based on the Company's ability to meet certain annual incentive thresholds relating to the number of wells connected to the Water Assets per year. In August 2019, the Company and the Purchaser agreed to terminate the incentive payments provision.

Upon closing, the Company dedicated all of the produced water from its oil and natural gas wells within its Monument Draw, Hackberry Draw and West Quito Draw operating areas to the Purchaser. There are no drilling or throughput commitments associated with the Water Infrastructure Divestiture. The Purchaser will receive a market price, subject to annual adjustments for inflation, in exchange for the transportation, disposal and treatment of such produced water, and the Purchaser will receive a market price for the supply of freshwater and recycled produced water to the Company.

During the three months ended December 31, 2018, the Company recognized a gain of $119.0 million on the sale of the Water Assets on the unaudited condensed consolidated statements of operations in "(Gain) loss on sale of Water Assets." The gain on the sale was reduced during the nine months ended September 30, 2019 by approximately $3.6 million as a result of customary post-closing adjustments.

The Company uses the full cost method of accounting for its investment in oil and natural gas properties. Under this method of accounting, all costs of acquisition, exploration and development of

oil and natural gas reserves (including such costs as leasehold acquisition costs, geological expenditures, dry hole costs, tangible and intangible development costs and direct internal costs) are capitalized as the cost of oil and natural gas properties when incurred. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depletion, exceed the discounted future net revenues of proved oil and natural gas reserves, net of deferred taxes, such excess capitalized costs are charged to expense.

Additionally, the Company assesses all properties classified as unevaluated property on a quarterly basis for possible impairment or reduction in value. The Company assesses properties on an individual basis or as a group, if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion and the full cost ceiling test limitation.

At September 30, 2019, the ceiling test value of the Company's reserves was calculated based on the first-day-of-the-month average for the 12-months ended September 30, 2019 of the West Texas Intermediate (WTI) crude oil spot price of $57.69 per barrel, adjusted by lease or field for quality, transportation fees, and regional price differentials, and the first-day-of-the-month average for the 12-months ended September 30, 2019 of the Henry Hub natural gas price of $2.87 per million British thermal units (MMBtu), adjusted by lease or field for energy content, transportation fees, and regional price differentials. Using these prices, the Company's net book value of oil and natural gas properties at September 30, 2019 exceeded the ceiling amount by $45.6 million which resulted in a ceiling test impairment charge of that amount for the quarter. The ceiling test impairment at September 30, 2019 was driven by decreases in the first-day-of-the-month 12-month average prices for crude oil used in the ceiling test calculation since June 30, 2019, when the first-day-of-month 12-month average price for crude oil was $61.45 per barrel. At June 30, 2019, the Company recorded a full cost ceiling impairment of $664.4 million. The ceiling test impairment at June 30, 2019 was primarily driven by the Company's continued focus on its most economic area, Monument Draw. Accordingly, the Company transferred approximately $481.7 million of unevaluated property costs to the full cost pool as of June 30, 2019, the majority of which were associated with the Company's Hackberry Draw area. At March 31, 2019, the Company recorded a full cost ceiling impairment of $275.2 million. The ceiling test impairment at March 31, 2019 was driven by a decrease in the first-day-of-the-month average price for crude oil used in the ceiling test calculation and the Company's intent to expend capital only on its most economic areas. As such, the Company identified certain leases in the Hackberry Draw area with near-term expirations and transferred approximately $51.0 million of associated unevaluated property costs to the full cost pool during the three months ended March 31, 2019. The impairments were recorded in "Full cost ceiling test impairment" on the unaudited condensed consolidated statements of operations.

At September 30, 2018, the ceiling test value of the Company's reserves was calculated based on the first-day-of-the-month average for the 12-months ended September 30, 2018 of the WTI crude oil spot price of $63.43 per barrel, adjusted by lease or field for quality, transportation fees, and regional price differentials, and the first-day-of-the-month average for the 12-months ended September 30, 2018 of the Henry Hub natural gas price of $2.91 per MMBtu, adjusted by lease or field for energy content,

transportation fees, and regional price differentials. Using these prices, the Company's net book value of oil and natural gas properties at September 30, 2018 did not exceed the ceiling amount.

Changes in commodity prices, production rates, levels of reserves, future development costs, transfers of unevaluated properties to the full cost pool, capital spending, and other factors will determine the Company's ceiling test calculations and impairment analyses in future periods.

On September 7, 2017, the Company and certain of its subsidiaries sold of all of the Company's operated oil and natural gas leases, oil and natural gas wells and related assets located in the Williston Basin in North Dakota, as well as 100% of the membership interests in two of its subsidiaries for a total adjusted sales price of approximately $1.39 billion (the Williston Divestiture). Under the full cost method of accounting, sales of oil and gas properties are accounted for as adjustments to capitalized costs with no gain or loss recognized, unless the adjustment significantly alters the relationship between capitalized costs and proved reserves. If the Williston Divestiture was accounted for as an adjustment of capitalized costs with no gain or loss recognized, the adjustment would have significantly altered the relationship between capitalized costs and proved reserves. Accordingly, the Company recognized a gain on the sale of the Williston Assets of $485.9 million during the year ended December 31, 2017. This gain was reduced by $7.2 million during the nine months ended September 30, 2018 as the result of customary post-closing adjustments. The carrying value of the properties sold was determined by allocating total capitalized costs within the full cost pool between properties sold and properties retained based on their relative fair values. The gain (loss) was recorded in "Gain (loss) on sale of oil and natural gas properties," on the Company's unaudited condensed consolidated statements of operations.

As of September 30, 2019 and December 31, 2018, the Company's debt consisted of the following (in thousands):

In connection with the chapter 11 proceedings and pursuant to an order of the Bankruptcy Court dated August 9, 2019 (the Interim Order), the Company entered into a Junior Secured Debtor-In-Possession Credit Agreement (the DIP Credit Agreement) with the Unsecured Senior Noteholders party thereto from time to time as lenders (the DIP Lenders) and Wilmington Trust, National Association, as administrative agent.

Under the DIP Credit Agreement, the DIP Lenders made available a $35.0 million debtor-in-possession junior secured term credit facility (the DIP Facility), of which $25.0 million was extended as an initial loan and the remainder of which was drawn on September 5, 2019. The DIP Facility was refinanced with a $750.0 million exit senior secured reserve-based revolving credit facility (the Exit Facility) on October 8, 2019. At September 30, 2019, the Company had $35.0 million of indebtedness outstanding under the DIP Facility.

The Company used the proceeds of the DIP Facility to, among other things, (i) provide working capital and other general corporate purposes, including to finance capital expenditures and make certain interest payments as and to the extent set forth in the Interim Order and/or the final order, as applicable, of the Bankruptcy Court and in accordance with the Company's budget delivered pursuant to the DIP Credit Agreement, (ii) pay fees and expenses related to the transactions contemplated by the DIP Credit Agreement in accordance with such budget and (iii) cash collateralize any letters of credit.

The DIP Loans bore interest at a rate per annum equal to (i) adjusted LIBOR plus an applicable margin of 5.50% or (ii) an alternative base rate plus an applicable margin of 4.50%, in each case, as selected by the Company.

The DIP Facility was secured by (i) a junior secured perfected security interest on all assets that secure the Senior Credit Agreement (defined below) and (ii) a senior secured perfected security interest on all unencumbered assets of the Company and any subsidiary guarantors. The security interests and liens were further subject to certain carve-outs and permitted liens, as set forth in the DIP Credit Agreement.

The DIP Credit Agreement contained certain customary (i) representations and warranties; (ii) affirmative and negative covenants, including delivery of financial statements; conduct of business; reserve reports; title information; indebtedness; liens; dividends and distributions; investments; sale or discount of receivables; mergers; sale of properties; termination of swap agreements; transactions with affiliates; negative pledges; dividend restrictions; gas imbalances; take-or-pay or other prepayments and swap agreements; and (iii) events of default, including non-payment; breaches of representations and warranties; non-compliance with covenants or other agreements; cross-default to material indebtedness; judgments; change of control; dismissal (or conversion to chapter 7) of the chapter 11 proceedings; and failure to satisfy certain bankruptcy milestones.

On September 7, 2017, the Company entered into an Amended and Restated Senior Secured Revolving Credit Agreement (the Senior Credit Agreement) by and among the Company, as borrower, JPMorgan Chase Bank, N.A., as administrative agent, and certain other financial institutions party thereto, as lenders. Pursuant to the Senior Credit Agreement, the lenders party thereto agreed to provide the Company with a $1.0 billion senior secured reserve-based revolving credit facility with a borrowing base of $225.0 million as of September 30, 2019. The maturity date of the Senior Credit Agreement was September 7, 2022. The borrowing base was redetermined semi-annually, with the lenders and the Company each having the right to one interim unscheduled redetermination between any two consecutive semi-annual redeterminations. The borrowing base took into account the estimated value of the Company's oil and natural gas properties, proved reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria. Amounts outstanding under the Senior Credit Agreement bore interest at specified margins over the base rate of 1.75% to 2.75% for ABR-based loans or at specified margins over LIBOR of 2.75% to 3.75% for Eurodollar-based loans. These margins fluctuated based on the Company's utilization of the facility. During the chapter 11 proceedings, amounts outstanding under the Senior Credit Agreement bore interest at a rate per annum equal to 2.0% plus the applicable interest rate in effect.

Amounts outstanding under the Senior Credit Agreement were guaranteed by certain of the Company's direct and indirect subsidiaries and secured by a security interest in substantially all of the assets of the Company and its subsidiaries.

The Senior Credit Agreement contained certain events of default, including non-payment; breaches of representations and warranties; non-compliance with covenants or other agreements; cross-default to material indebtedness; judgments; change of control; and voluntary and involuntary bankruptcy. The Senior Credit Agreement also contained certain financial covenants, including the maintenance of (i) a Consolidated Total Net Debt to EBITDA Ratio (each as defined in the Senior Credit Agreement) and (ii) a Current Ratio (as defined in the Senior Credit Agreement) not to be less than 1.00 to 1.00.

On May 9, 2019, the Company entered into the Eighth Amendment, Consent and Waiver to Amended and Restated Senior Secured Credit Agreement (the Eighth Amendment) which, among other things, (i) temporarily waived any default or event of default directly resulting from the potential Leverage Ratio Default (as defined in the Eighth Amendment) for the fiscal quarter ended March 31, 2019, (ii) increased interest margins to 1.75% to 2.75% for ABR-based loans and 2.75% to 3.75% for Eurodollar-based loans, (iii) reduced the Company's Consolidated Cash Balance (as defined in the Eighth Amendment) to $5.0 million, and (iv) provided for periodic reporting of projected cash flows and accounts payable agings to the lenders. Under the Eighth Amendment, the waiver would have terminated and an Event of Default (as defined in the Senior Credit Agreement) would have occurred on August 1, 2019. On July 31, 2019, the Company entered into the Waiver to Amended and Restated Senior Secured Credit Agreement, pursuant to which the termination date for the waiver granted by the Eighth Amendment was extended to August 8, 2019.

On February 28, 2019, the lenders party to the Senior Credit Agreement issued a consent (the Severance and Office Payments Consent) to the Company whereby Severance Payments and Office Payments (as defined in the Severance and Office Payments Consent) may exceed the maximum level allowed for adding back non-recurring expenses and charges in the definition of EBITDA (as defined

in the Senior Credit Agreement) when calculating the ratio of Consolidated Total Net Debt to EBITDA (as defined in the Senior Credit Agreement) for the fiscal quarter ending March 31, 2019.

On February 15, 2019, the Company entered into the Seventh Amendment (the Seventh Amendment) to the Senior Credit Agreement which, among other things, provided for (i) the use of annualized financial data in determining EBITDA (as defined in the Senior Credit Agreement) for the fiscal quarters ending March 31, 2019, June 30, 2019 and September 30, 2019 and (ii) amended the ratio of Consolidated Total Net Debt (as defined in the Senior Credit Agreement) to EBITDA to be (a) 5.00 to 1.0 for the fiscal quarter ending March 31, 2019, (b) 4.75 to 1.0 for the fiscal quarter ending June 30, 2019, (c) 4.5 to 1.0 for the fiscal quarter ending September 30, 2019, (d) 4.25 to 1.0 for the fiscal quarter ending December 31, 2019, and (e) 4.0 to 1.0 for the fiscal quarter ending March 31, 2020 and any fiscal quarter thereafter.

On November 6, 2018, the lenders party to the Senior Credit Agreement issued a consent (the H2S Consent) to the Company whereby H2S Expenses (as defined in the H2S Consent) may exceed the maximum level allowed for adding back non-recurring expenses and charges in the definition of EBITDA (as defined in the Senior Credit Agreement) when calculating the ratio of Consolidated Total Net Debt to EBITDA (as defined in the Senior Credit Agreement) for the fiscal quarters ending September 30, 2018, December 31, 2018 and March 31, 2019.

At September 30, 2019, the Company had $223.2 million of indebtedness outstanding and approximately $1.8 million letters of credit outstanding. On October 8, 2019, borrowings outstanding under the Senior Credit Agreement were repaid and refinanced with proceeds from the Equity Rights Offerings and borrowings under the Exit Facility.

On February 16, 2017, the Company issued $850.0 million aggregate principal amount of new 6.75% senior unsecured notes due 2025 (the 2025 Notes) in a private placement exempt from registration under Section 4(a)(2) of the Securities Act of 1933, as amended (Securities Act), Rule 144A and Regulation S, and applicable state securities laws. The 2025 Notes were issued at par and bear interest at a rate of 6.75% per annum, payable semi-annually on February 15 and August 15 of each year. The maturity date of the 2025 Notes was February 15, 2025. Proceeds from the private placement were approximately $834.1 million after deducting initial purchasers' discounts and commissions and offering expenses. The Company used a portion of the net proceeds from the private placement to fund the repurchase and redemption of the then outstanding 8.625% senior secured second lien notes, and for general corporate purposes. The 2025 Notes were governed by an Indenture, dated as of February 16, 2017 (as supplemented, the February 2017 Indenture) by and among the Company, the Guarantors and U.S. Bank National Association, as Trustee, which contained affirmative and negative covenants that, among other things, limit the ability of the Company and the Guarantors to incur indebtedness; purchase or redeem stock or subordinated indebtedness; make investments; create liens; enter into transactions with affiliates; sell assets; refinance certain indebtedness; merge with or into other companies or transfer substantially all of their assets; and, in certain circumstances, to pay dividends or make other distributions on stock. The February 2017 Indenture also contained customary events of default. Upon the occurrence of certain events of default, the Trustee or the holders of the 2025 Notes may declare all outstanding 2025 Notes to be due and payable immediately. The 2025 Notes were jointly and severally, fully and unconditionally guaranteed on a senior unsecured

basis by the Company's existing wholly-owned subsidiaries. Halcón, the issuer of the 2025 Notes, has no material independent assets or operations apart from the assets and operations of its subsidiaries.

In connection with the sale of the 2025 Notes, on February 16, 2017, the Company, the Guarantors and J.P. Morgan Securities LLC, on behalf of itself and as representative of the initial purchasers, entered into a Registration Rights Agreement (the 2017 Registration Rights Agreement) pursuant to which the Company agreed to, among other things, use reasonable best efforts to file a registration statement under the Securities Act and complete an exchange offer for the 2025 Notes within 365 days after closing. The Company completed the exchange offer for the 2025 Notes on February 1, 2018.

On July 25, 2017, the Company concluded a consent solicitation of the holders of the 2025 Notes (the Consent Solicitation) and obtained consents to amend the February 2017 Indenture from approximately 99% of the holders of the 2025 Notes. As supplemented, the February 2017 Indenture exempted, among other things, the Williston Divestiture from certain provisions triggered upon a sale of "all or substantially all of the assets" of the Company. Consenting holders of the 2025 Notes received a consent fee of 2.0% of principal, or $16.9 million. The Company recorded the $16.9 million consent fees paid as a discount on the 2025 Notes.

On September 7, 2017, the Company commenced an offer to purchase for cash up to $425.0 million of the $850.0 million outstanding aggregate principal amount of its 2025 Notes at 103.0% of principal plus accrued and unpaid interest. The consummation of the Williston Divestiture constituted a "Williston Sale" under the February 2017 Indenture, and the Company was required to make an offer to all holders of the 2025 Notes to purchase for cash an aggregate principal amount up to $425.0 million of the 2025 Notes. The offer to purchase expired on October 6, 2017, with notes representing in excess of $425.0 million of principal amount validly tendered. As a result, on October 10, 2017, the Company repurchased approximately $425.0 million principal amount of the 2025 Notes on a pro rata basis at 103.0% of par plus accrued and unpaid interest of approximately $4.1 million.

On February 15, 2018, the Company issued an additional $200.0 million aggregate principal amount of its 2025 Notes at a price to the initial purchasers of 103.0% of par (the Additional 2025 Notes). The net proceeds from the sale of the Additional 2025 Notes were approximately $202.4 million after deducting initial purchasers' premiums, commissions and estimated offering expenses. The proceeds were used to fund the cash consideration for the acquisition of the West Quito Draw Properties, discussed further in Note 4, "Acquisitions and Divestitures," and for general corporate purposes, including to fund the Company's 2018 drilling program. These notes were issued under the February 2017 Indenture. The Additional 2025 Notes were treated as a single class with, and have the same terms as, the 2025 Notes.

On the Petition Date, the 2025 Notes represented "Liabilities subject to compromise" and the corresponding discount of $6.6 million and premium of $4.9 million were written-off to "Reorganization items" on the unaudited condensed consolidated statements of operations. See Note 1, "Financial Statement Presentation" for more details on liabilities subject to compromise. On the Effective Date, the 2025 Notes were cancelled. See Note 2, "Reorganization" for further details.

The Company capitalizes certain direct costs associated with the issuance of debt and amortizes such costs over the lives of the respective debt. For the nine months ended September 30, 2019, the Company wrote off to "Reorganization items" $9.3 million of debt issuance costs in conjunction with its liabilities subject to compromise and expensed to "Interest expense and other" $0.7 million of debt issuance costs in conjunction with refinancing the Senior Credit Agreement and a decrease in the borrowing base under the Senior Credit Agreement. At September 30, 2019 and December 31, 2018, the Company had zero and approximately $11.1 million, respectively, of unamortized debt issuance costs. The debt issuance costs for the Company's Senior Credit Agreement were presented in "Funds in escrow and other" within total assets on the unaudited condensed consolidated balance sheet, and the debt issuance costs for the Company's senior unsecured debt were presented in "Long-term debt, net" within total liabilities on the unaudited condensed consolidated balance sheet.

Pursuant to ASC 820, Fair Value Measurements (ASC 820), the Company's determination of fair value incorporates not only the credit standing of the counterparties involved in transactions with the Company resulting in receivables on the Company's unaudited condensed consolidated balance sheets, but also the impact of the Company's nonperformance risk on its own liabilities. ASC 820 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). ASC 820 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy assigns the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Level 2 measurements are inputs that are observable for assets or liabilities, either directly or indirectly, other than quoted prices included within Level 1. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. The Company classifies fair value balances based on the observability of those inputs.

As required by ASC 820, a financial instrument's level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There were no transfers between fair value hierarchy levels for any period presented. The following tables set forth by level within the fair value hierarchy the Company's financial assets and

liabilities that were accounted for at fair value as of September 30, 2019 and December 31, 2018 (in thousands):

Derivative contracts listed above as Level 2 include collars, puts, calls, fixed-price swaps and basis swaps that are carried at fair value. The Company records the net change in the fair value of these positions in "Net gain (loss) on derivative contracts" on the unaudited condensed consolidated statements of operations. The Company is able to value the assets and liabilities based on observable market data for similar instruments, which resulted in the Company reporting its derivatives as Level 2. This observable data includes the forward curves for commodity prices based on quoted market prices and implied volatility factors related to changes in the forward curves. See Note 9, "Derivative and Hedging Activities," for additional discussion of derivatives.

The Company's derivative contracts are with major financial and commodity hedging institutions with investment grade credit ratings which are believed to have minimal credit risk. As such, the Company is exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts; however, the Company does not anticipate such nonperformance. The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of ASC 825, Financial Instruments. The estimated fair value amounts have been determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash and cash equivalents, accounts receivables and accounts payables approximate their carrying value due to their short-term nature. The estimated fair value of the Company's Senior Credit Agreement and DIP Credit Agreement approximate carrying value because the interest rates approximate current market rates. The following table presents the estimated fair value of the Company's fixed interest rate debt

instrument as of September 30, 2019 and December 31, 2018 (excluding discounts, premiums and debt issuance costs) (in thousands):

The fair value of the Company's fixed interest rate debt instrument was calculated using Level 1 criteria. The fair value of the Company's senior notes is based on quoted market prices from trades of such debt.

The Company follows the provisions of ASC 820 for nonfinancial assets and liabilities measured at fair value on a non-recurring basis. These provisions apply to the Company's initial recognition of asset retirement obligations for which fair value is used. The asset retirement obligation estimates are derived from historical costs and management's expectation of future cost environments; and therefore, the Company has designated these liabilities as Level 3. See Note 10, "Asset Retirement Obligations," for a reconciliation of the beginning and ending balances of the liability for the Company's asset retirement obligations.

The Company is exposed to certain risks relating to its ongoing business operations, such as commodity price risk and interest rate risk. Derivative contracts are utilized to hedge the Company's exposure to price fluctuations and reduce the variability in the Company's cash flows associated with anticipated sales of future oil, natural gas and natural gas liquids production. When derivative contracts are available at terms (or prices) acceptable to the Company, it generally hedges a substantial, but varying, portion of anticipated oil, natural gas and natural gas liquids production for future periods. Derivatives are carried at fair value on the unaudited condensed consolidated balance sheets as assets or liabilities, with the changes in the fair value included in the unaudited condensed consolidated statements of operations for the period in which the change occurs. The Company's hedge policies and objectives may change significantly as its operational profile changes and/or commodities prices change. The Company does not enter into derivative contracts for speculative trading purposes.

It is the Company's policy to enter into derivative contracts only with counterparties that are creditworthy financial or commodity hedging institutions deemed by management as competent and competitive market makers. As of September 30, 2019, the Company did not post collateral under any of its derivative contracts as they are secured under the Company's Senior Credit Agreement or are uncollateralized trades.

The Company's crude oil, natural gas and natural gas liquids derivative positions at any point in time may consist of fixed-price swaps, basis swaps and costless put/call "collars." Fixed-price swaps are designed so that the Company receives or makes payments based on a differential between fixed and variable prices for crude oil and natural gas. Basis swaps effectively lock in a price differential between

regional prices (i.e. Midland) where the product is sold and the relevant price index under which the production is hedged (i.e. Cushing). A costless collar consists of a sold call, which establishes a maximum price the Company will receive for the volumes under contract and a purchased put that establishes a minimum price. The Company has elected not to designate any of its derivative contracts for hedge accounting. Accordingly, the Company records the net change in the mark-to-market valuation of these derivative contracts, as well as payments and receipts on settled derivative contracts, in "Net gain (loss) on derivative contracts" on the unaudited condensed consolidated statements of operations.

All derivative contracts are recorded at fair market value in accordance with ASC 815, Derivatives and Hedging (ASC 815) and ASC 820 and included in the unaudited condensed consolidated balance sheets as assets or liabilities. The following table summarizes the location and fair value amounts of all derivative contracts in the unaudited condensed consolidated balance sheets (in thousands):

The following table summarizes the location and amounts of the Company's realized and unrealized gains and losses on derivative contracts in the Company's unaudited condensed consolidated statements of operations (in thousands):

		Amount of gain or (loss) recognized in income on derivative contracts for the					Amount of gain or (loss) recognized in income on derivative contracts for the

		Three Months Ended September 30,					Nine Months Ended September 30,
Derivatives not designated as hedging contracts under ASC 815	Location of gain or (loss) recognized in income on derivative contracts	Three Months Ended September 30,					Nine Months Ended September 30,
		2019		2018			2019			2018
Commodity contracts:
Unrealized gain (loss) on commodity contracts	Other income (expenses)—net gain (loss) on derivative contracts	$	11,571	$	(50,763	)	$	(45,834	)	$	(77,524	)
Realized gain (loss) on commodity contracts	Other income (expenses)—net gain (loss) on derivative contracts		1,886		(9,643	)		11,502			10,921

Total net gain (loss) on derivative contracts		$	13,457	$	(60,406	)	$	(34,332	)	$	(66,603	)

At September 30, 2019 and December 31, 2018, the Company had the following open crude oil, natural gas liquids and natural gas derivative contracts:

			September 30, 2019

					Floors			Ceilings			Basis Differential
Period	Instrument	Commodity	Volume in Mmbtu's/ Bbl's		Price / Price Range	Weighted Average Price		Price / Price Range	Weighted Average Price		Price / Price Range	Weighted Average Price
October 2019 - December 2019	Basis Swap	Crude Oil		828,000	$—	$	—	$—	$	—	$(6.50) - $4.00	$	0.31
October 2019 - December 2019	Collars	Crude Oil		736,000	50.00 - 55.85		52.61	55.00 - 60.85		57.89
October 2019 - December 2019	Basis Swap	Natural Gas		2,346,000							(1.05) - (1.40)		(1.18	)
October 2019 - December 2019	Collars	Natural Gas		1,978,000	2.52 - 2.70		2.60	3.00 - 3.10		3.01
October 2019 - December 2019	Swap	Natural Gas Liquids		322,000	29.08 - 29.50		29.21
October 2019 - December 2019	WTI NYMEX ROLL	Crude Oil		460,000	0.35		0.35
January 2020 - December 2020	Swap	Crude Oil		366,000	60.00		60.00
January 2020 - December 2020	Basis Swap	Crude Oil		3,294,000							2.00 - 4.00		2.95
January 2020 - December 2020	Collars	Crude Oil		549,000	50.00		50.00	70.00		70.00
January 2020 - December 2020	Calls	Crude Oil		2,342,400				70.00		70.00
January 2020 - December 2020	Puts	Crude Oil		915,000	55.00		55.00

			December 31, 2018

						Floors			Ceilings			Basis Differential
Period	Instrument	Commodity	Volume in Mmbtu's/ Bbl's			Price / Price Range	Weighted Average Price		Price / Price Range	Weighted Average Price		Price / Price Range	Weighted Average Price
January 2019 - March 2019	Calls	Crude Oil		1,350,000		$—	$	—	$62.64	$	62.64	$—	$	—
January 2019 - March 2019	Calls	Crude Oil		(1,350,000	)				58.64		58.64
January 2019 - March 2019	Collars	Crude Oil		90,000		46.75		46.75	51.75		51.75
January 2019 - June 2019	Collars	Crude Oil		181,000		51.00		51.00	56.00		56.00
January 2019 - September 2019	Basis Swap	Crude Oil		546,000								(6.20) - (7.60)		(6.90	)
January 2019 - December 2019	Basis Swap	Crude Oil		2,448,000								(0.98) - (6.50)		(2.80	)
January 2019 - December 2019	Basis Swap	Natural Gas		9,307,500								(1.05) - (1.40)		(1.18	)
January 2019 - December 2019	Collars	Crude Oil		3,650,000		50.00 - 58.00		53.87	55.20 - 63.00		60.07
January 2019 - December 2019	Collars	Natural Gas		8,760,000		2.52 - 2.70		2.60	3.00 - 3.10		3.01
January 2019 - December 2019	Swap	Natural Gas Liquids		1,460,000		29.08 - 30.15		29.33
January 2019 - December 2019	WTI NYMEX ROLL	Crude Oil		1,825,000		0.35		0.35
April 2019 - June 2019	Collars	Crude Oil		91,000		50.00		50.00	55.00		55.00
April 2019 - December 2019	Collars	Crude Oil		275,000		55.00		55.00	62.85		62.85
July 2019 - December 2019	Basis Swap	Crude Oil		460,000								(2.40) - (6.50)		(5.68	)
July 2019 - December 2019	Collars	Crude Oil		552,000		50.00 - 55.00		53.00	55.00 - 69.00		61.00
October 2019 - December 2019	Basis Swap	Crude Oil		460,000								3.45 - 4.00		3.72
October 2019 - December 2019	Collars	Crude Oil		92,000		51.00		51.00	56.00		56.00
October 2019 - December 2019	Swap	Natural Gas Liquids		92,000		32.50		32.50
January 2020 - December 2020	Basis Swap	Crude Oil		3,294,000								2.00 - 4.00		2.95
January 2020 - December 2020	Collars	Crude Oil		549,000		50.00		50.00	70.00		70.00
January 2020 - December 2020	Calls	Crude Oil		2,342,400					70.00		70.00
January 2020 - December 2020	Puts	Crude Oil		915,000		55.00		55.00

The Company presents the fair value of its derivative contracts at the gross amounts in the unaudited condensed consolidated balance sheets. The following table shows the potential effects of master netting arrangements on the fair value of the Company's derivative contracts at September 30, 2019 and December 31, 2018 (in thousands):

The Company enters into an International Swap Dealers Association Master Agreement (ISDA) with each counterparty prior to a derivative contract with such counterparty. The ISDA is a standard contract that governs all derivative contracts entered into between the Company and the respective counterparty. The ISDA allows for offsetting of amounts payable or receivable between the Company and the counterparty, at the election of both parties, for transactions that occur on the same date and in the same currency.

The filing of the voluntary petitions for relief under chapter 11 of the Bankruptcy Code described in Note 2, "Reorganization," constituted an event of default under the Company's derivatives contracts that gave the counterparties the option to terminate such contracts. Certain parties elected to terminate their contracts in August 2019 and the Company received approximately $0.1 million to settle a portion of the outstanding positions while other positions were novated for fees totaling $0.5 million. The remaining derivative contracts, including the novated positions, were secured on a super-priority pari passu basis with the Company's Senior Credit Agreement during the bankruptcy process and remain in place following the Company's chapter 11 proceedings.

The Company records an asset retirement obligation (ARO) on oil and natural gas properties when it can reasonably estimate the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon costs. For other operating property and equipment, the Company records an ARO when the system is placed in service and it can reasonably estimate the fair value of an obligation to perform site reclamation and other necessary work when it is required. The Company records the ARO liability on the unaudited condensed consolidated balance sheets and capitalizes a portion of the cost in "Oil and natural gas properties" or "Other operating property and equipment" during the period in which the obligation is incurred. The Company records the accretion of its ARO liabilities in "Depletion, depreciation and accretion" expense in the unaudited condensed consolidated statements of operations. The additional capitalized costs are depreciated on a unit-of-production basis or straight-line basis.

The Company recorded the following activity related to its ARO liability for the period indicated below (inclusive of the current portion) (in thousands):

As of September 30, 2019, the Company has the following rig termination commitment related to a historical rig contract (in thousands):

As of September 30, 2019, the Company has the following purchase commitments related to equipment (in thousands):

The Company has entered into various long-term gathering, transportation and sales contracts with respect to its oil and natural gas production from the Delaware Basin in West Texas. As of September 30, 2019, the Company had in place three long-term crude oil contracts and eleven long-term natural gas contracts in this area and the sales price under these contracts are based on posted market rates. Under the terms of these contracts, the Company has committed a substantial portion of its production from these areas for periods ranging from one to twenty years from the date of first production.

On February 26, 2019, a subsidiary of the Company, Halcón Energy Properties, Inc. (HEPI), filed notice of appeal from a judgment entered by The Court of Common Pleas of Mercer County, Pennsylvania in a litigation matter captioned Vodenichar, et al., v. Halcón Energy Properties, Inc. et al., No. 2013-0512, arising from a dispute over whether the subsidiary complied with the terms of a letter of intent related to the leasing of acreage, pursuant to which HEPI was ordered to pay $9,107,053.57 (including interest and costs). Such appeal is currently pending in the Superior Court of Pennsylvania, Western District (Case No. 347 WDA 2019).

In addition to the above, from time to time, the Company may be a plaintiff or defendant in a pending or threatened legal proceeding arising in the normal course of our business. While the outcome and impact of currently pending legal proceedings cannot be determined, the Company's management and legal counsel believe that the resolution of these proceedings through settlement or adverse judgment will not have a material effect on the Company's consolidated operating results, financial position or cash flows.

On February 9, 2018, the Company sold 9.2 million shares of common stock, par value $0.0001 per share, in a public offering at a price of $6.90 per share. The net proceeds to the Company from the offering were approximately $60.4 million, after deducting the underwriters' discounts and offering expenses. The Company used the net proceeds, together with the net proceeds from the issuance of the Additional 2025 Notes, to fund the cash consideration for the acquisition of the West Quito Draw Properties, and for general corporate purposes, including funding the Company's 2018 drilling program.

On the Effective Date, all shares of the predecessor company were cancelled, see Note 15, "Subsequent Events" for further details related to the impact of emergence from chapter 11 bankruptcy on the Company's equity and common stock outstanding.

On September 9, 2016, the Company issued 4.7 million new warrants. The warrants could be exercised to purchase 4.7 million shares of the Company's common stock at an exercise price of $14.04 per share. The holders were entitled to exercise the warrants in whole or in part at any time prior to expiration on September 9, 2020. On the Effective Date, all warrants of the predecessor company were cancelled, see Note 15, "Subsequent Events" for further details related to the impact of emergence from chapter 11 bankruptcy on the Company's warrants.

On September 9, 2016, the Company's Board adopted the 2016 Long-Term Incentive Plan (the Incentive Plan). An aggregate of 10.0 million shares of the Company's common stock were available for grant pursuant to awards under the Incentive Plan. On April 6, 2017, Amendment No. 1 to the Incentive Plan to increase, by 9.0 million shares, the maximum number of shares of common stock that may be issued thereunder, i.e., a maximum of 19.0 million shares, became effective, which was 20 calendar days following the date the Company mailed an information statement to all stockholders of

record notifying them of approval of the amendment by written consent of holders of a majority of the Company's outstanding stock. As of September 30, 2019 and December 31, 2018, a maximum of 8.0 million and 4.9 million shares, respectively, of the Company's common stock remained reserved for issuance under the Incentive Plan. Immediately prior to the Effective Date, all outstanding stock-based compensation awards granted thereunder were either vested or cancelled, see Note 15, "Subsequent Events" for further details related to the impact of emergence from chapter 11 bankruptcy.

The Company accounts for stock-based payment accruals under authoritative guidance on stock compensation. The guidance requires all stock-based payments to employees and directors, including grants of stock options and restricted stock, to be recognized in the financial statements based on their fair values. The Company has elected to not apply a forfeiture estimate and will recognize a credit in compensation expense to the extent awards are forfeited. For the three and nine months ended September 30, 2019, the Company recognized a credit of $2.3 million and $8.0 million, respectively, related to stock-based compensation recorded as a component of "General and administrative" on the unaudited condensed consolidated statements of operations. During the nine months ended September 30, 2019, senior executives departed the Company. In accordance with the terms of these senior executives' employment agreements, unvested stock options and unvested shares of restricted stock were modified to vest immediately upon termination or approval by the Bankruptcy Court. For the three and nine months ended September 30, 2019, the Company recognized incremental reductions to stock-based compensation expense of $1.1 million and $9.5 million, respectively, associated with these modifications.

For the three and nine months ended September 30, 2018, the Company recognized an expense of $4.4 million and $12.2 million, respectively, related to stock-based compensation recorded as a component of "General and administrative" on the unaudited condensed consolidated statements of operations.

From time to time, the Company grants stock options under the Incentive Plan covering shares of common stock to employees of the Company. Stock options, when exercised, are settled through the payment of the exercise price in exchange for new shares of stock underlying the option. These awards typically vest over a three year period at a rate of one-third on the annual anniversary date of the grant and expire ten years from the grant date.

No stock options were granted during the nine months ended September 30, 2019. At September 30, 2019, the Company had $0.2 million of unrecognized compensation expense related to non-vested stock options to be recognized over a weighted-average period of 0.8 years.

During the nine months ended September 30, 2018, the Company granted stock options under the Incentive Plan covering 1.2 million shares of common stock to employees of the Company. These stock options have an exercise price of $5.65. During the nine months ended September 30, 2018, the Company received $0.3 million from the exercise of stock options. At September 30, 2018, the Company had $7.1 million of unrecognized compensation expense related to non-vested stock options to be recognized over a weighted-average period of 1.1 years.

From time to time, the Company grants shares of restricted stock to employees and non-employee directors of the Company. Employee shares typically vest over a three year period at a rate of one-third on the annual anniversary date of the grant, and the non-employee directors' shares vest six months from the date of grant.

During the nine months ended September 30, 2019, the Company granted 4.2 million shares of restricted stock under the Incentive Plan to employees and non-employee directors of the Company. These restricted shares were granted at prices ranging from $1.29 to $1.40 with a weighted average price of $1.29 per share. At September 30, 2019, the Company had $2.7 million of unrecognized compensation expense related to non-vested restricted stock awards to be recognized over a weighted-average period of 1.3 years.

During the nine months ended September 30, 2018, the Company granted 2.3 million shares of restricted stock under the Incentive Plan to employees and non-employee directors of the Company. These restricted shares were granted at prices ranging from $3.75 to $5.65 with a weighted average price of $5.47. At September 30, 2018, the Company had $8.6 million of unrecognized compensation expense related to non-vested restricted stock awards to be recognized over a weighted-average period of 1.2 years.

The following represents the calculation of earnings (loss) per share (in thousands, except per share amounts):

	Three Months Ended September 30,						Nine Months Ended September 30,

	2019			2018			2019			2018
Basic:
Net income (loss)	$	(63,284	)	$	(81,837	)	$	(1,040,687	)	$	(100,709	)



Weighted average basic number of common shares outstanding		159,143			158,011			158,916			156,628

Basic net income (loss) per share of common stock	$	(0.40	)	$	(0.52	)	$	(6.55	)	$	(0.64	)



Diluted:
Net income (loss)	$	(63,284	)	$	(81,837	)	$	(1,040,687	)	$	(100,709	)



Weighted average basic number of common shares outstanding		159,143			158,011			158,916			156,628
Common stock equivalent shares representing shares issuable upon:
Exercise of stock options		Anti-dilutive			Anti-dilutive			Anti-dilutive			Anti-dilutive
Exercise of warrants		Anti-dilutive			Anti-dilutive			Anti-dilutive			Anti-dilutive
Vesting of restricted shares		Anti-dilutive			Anti-dilutive			Anti-dilutive			Anti-dilutive

Weighted average diluted number of common shares outstanding		159,143			158,011			158,916			156,628

Diluted net income (loss) per share of common stock	$	(0.40	)	$	(0.52	)	$	(6.55	)	$	(0.64	)

Common stock equivalents, including stock options, restricted shares and warrants totaling 11.8 million and 14.1 million shares for the three and nine months ended September 30, 2019, respectively, were not included in the computation of diluted earnings per share of common stock because the effect would have been anti-dilutive due to the net losses.

Common stock equivalents, including stock options, restricted shares and warrants totaling 14.9 million and 14.3 million shares for the three and nine months ended September 30, 2018, respectively, were not included in the computation of diluted earnings per share of common stock because the effect would have been anti-dilutive due to the net losses.

	September 30, 2019		December 31, 2018

Accounts receivable:
Oil, natural gas and natural gas liquids revenues	$	26,584	$	26,432
Joint interest accounts		9,556		7,369
Other		1,686		1,917

	$	37,826	$	35,718



Prepaids and other:
Prepaids	$	6,625	$	3,503
Income tax receivable		1,250		1,250
Funds in escrow		6,732		—
Other		35		35

	$	14,642	$	4,788



Funds in escrow and other:
Funds in escrow	$	578	$	570
Other		560		1,611

	$	1,138	$	2,181



Accounts payable and accrued liabilities:
Trade payables	$	51,594	$	68,959
Accrued oil and natural gas capital costs		25,445		41,461
Revenues and royalties payable		18,970		20,526
Accrued interest expense		3,480		16,971
Accrued employee compensation		2,621		3,421
Accrued lease operating expenses		10,029		6,292
Other		439		218

	$	112,578	$	157,848

On August 7, 2019, the Halcón Entities filed voluntary petitions for relief under chapter 11 of the United States Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of Texas to pursue the Plan. On September 24, 2019, the Bankruptcy Court entered an order confirming the Plan and on October 8, 2019, the Plan became effective and the Halcón Entities emerged from chapter 11 bankruptcy.

Upon emergence from chapter 11 bankruptcy, the Company qualified for and adopted fresh-start accounting in accordance with the provisions set forth in ASC 852 as (i) the reorganization value of the Company's assets immediately prior to the date of confirmation was less than the postpetition liabilities and allowed claims, and (ii) the holders of the existing voting shares of the predecessor entity received less than 50% of the voting shares of the emerging entity. Fresh-start accounting requires the Company to present its assets, liabilities, and equity as if it were a new entity upon emergence from bankruptcy. The new entity will be referred to as "successor" or "successor company." However, the Company will continue to present financial information for any periods before adoption of fresh-start accounting for the predecessor company. The predecessor and successor companies may lack comparability, as required in ASC 205, Presentation of Financial Statements (ASC 205). ASC 205 states financial statements are required to be presented comparably from year to year, with any exceptions to comparability clearly disclosed. Therefore, "black-line" financial statements are required to be presented to distinguish between the predecessor and successor companies.

Adopting fresh-start accounting results in a new financial reporting entity with no beginning retained earnings or deficit as of the fresh-start reporting date. Upon the application of fresh-start accounting, the Company will allocate the reorganization value (the fair value of the successor company's total assets) to its individual assets based on their estimated fair values. The reorganization value is intended to represent the approximate amount a willing buyer would value the Company's assets immediately after the reorganization. Reorganization value is derived from an estimate of enterprise value, or the fair value of the Company's long-term debt and stockholders' equity less cash. The process of estimating the fair value of the Company's assets, liabilities and equity upon emergence is currently ongoing and, therefore, such amounts have not yet been finalized. In support of the Plan, the enterprise value of the successor company was estimated and approved by the Bankruptcy Court to be in the range of $425.0 million and $475.0 million.

On the Effective Date, the Company entered into a senior secured revolving credit agreement with Bank of Montreal, as administrative agent, and certain other financial institutions party thereto, as lenders, which refinanced the DIP Facility and Senior Credit Agreement. The Exit Facility provides for a $750.0 million senior secured reserve-based revolving credit facility. The Exit Facility has an initial borrowing base of $275.0 million and on the Effective Date, the Company made an initial draw of $130.0 million. A portion of the Exit Facility, in the amount of $50 million, is available for the issuance of letters of credit. The maturity date of the Exit Facility is October 8, 2024. The first redetermination will be in the spring of 2020 and redeterminations will occur semi-annually thereafter, with the lenders and the Company each having the right to one interim unscheduled redetermination between any two consecutive semi-annual redeterminations. The borrowing base takes into account the estimated value of the Company's oil and natural gas properties, proved reserves, total indebtedness, and other relevant

factors consistent with customary oil and natural gas lending criteria. Amounts outstanding under the Exit Facility bear interest at specified margins over the base rate of 1.00% to 2.00% for ABR-based loans or at specified margins over LIBOR of 2.00% to 3.00% for Eurodollar-based loans, which margins may be increased one-time by not more than 50 basis points per annum if necessary in order to successfully syndicate the Exit Facility, which is currently in process. These margins fluctuate based on the Company's utilization of the facility.

The Company may elect, at its option, to prepay any borrowings outstanding under the Exit Credit Agreement without premium or penalty (except with respect to any break funding payments which may be payable pursuant to the terms of the Exit Credit Agreement). The Company may be required to make mandatory prepayments of the Loans under the Exit Facility in connection with certain borrowing base deficiencies, including deficiencies which may arise in connection with a borrowing base redetermination, an asset disposition or swap terminations attributable in the aggregate to more than ten percent (10%) of the then-effective borrowing base. Amounts outstanding under the Exit Credit Agreement are guaranteed by the Company's direct and indirect subsidiaries and secured by a security interest in substantially all of the assets of the Company and its subsidiaries.

The Exit Credit Agreement contains certain events of default, including non-payment; breaches of representation and warranties; non-compliance with covenants; cross-defaults to material indebtedness; voluntary or involuntary bankruptcy; judgments and change in control. The Exit Credit Agreement also contains certain financial covenants, including the maintenance of (i) a Total Net Indebtedness Leverage Ratio (as defined in the Exit Credit Agreement) not to exceed 4.00:1.00, determined as of each four fiscal quarter periods and commencing with the fiscal quarter ending March 31, 2020 and (ii) a Current Ratio (as defined in the Exit Credit Agreement) not to be less than 1.00:1.00, commencing with the fiscal quarter ending March 31, 2020.

On the Effective Date, pursuant to the terms of the Plan, all shares of the predecessor company were cancelled and the Company filed an amended and restated certificate of incorporation with the Delaware Secretary of State and adopted amended and restated bylaws. Pursuant to the amended and restated certificate of incorporation, the number of authorized shares of common stock which the Company has the authority to issue was reduced from 1,001,000,000 to 101,000,000. Of the 101,000,000 authorized shares, 100,000,000 are common stock, par value $0.0001 per share and 1,000,000 are preferred stock, par value $0.0001 per share.

On the Effective Date, pursuant to the terms of the Plan and the confirmation order, the Company issued:

On the Effective Date, by operation of the Plan and the confirmation order, all warrants of the predecessor company were cancelled and the Company entered into a warrant agreement (the Warrant Agreement) with Broadridge Corporate Issuer Solutions, Inc., pursuant to which the Company issued three series of warrants (the Series A Warrants, the Series B Warrants and the Series C Warrants and together, the Warrants, and the holders thereof, the Warrant Holders), on a pro rata basis to pre-emergence holders of the Company's Existing Equity Interests pursuant to the Plan.

Each Warrant represents the right to purchase one share of New Common Shares at the applicable exercise price, subject to adjustment as provided in the Warrant Agreement and as summarized below. On the Effective Date, the Company issued (i) Series A Warrants to purchase an aggregate of 1,798,322 shares of New Common Stock, with an initial exercise price of $40.17 per share, (ii) Series B Warrants to purchase an aggregate of 2,247,985 shares of New Common Stock, with an initial exercise price of $48.28 per share and (iii) Series C Warrants to purchase an aggregate of 2,890,271shares of New Common Stock, with an initial exercise price of $60.45 per share. Each series of Warrants issued under the Warrant Agreement has a three-year term, expiring on October 8, 2022. The strike price of each series of Warrants issued under the Warrant Agreement increases monthly, as provided in the Warrant Agreement.

The Warrants do not grant the Warrant Holder any voting or control rights or dividend rights, or contain any negative covenants restricting the operation of the Company's business.

On the Effective Date, the Company and the other signatories thereto (the Demand Stockholders), entered into a registration rights agreement (the Registration Rights Agreement), pursuant to which, subject to certain conditions and limitations, the Company agreed to file with the SEC a registration statement concerning the resale of the registrable shares of New Common Shares of the Company held by Demand Stockholders (the Registrable Securities), as soon as reasonably practicable but in no event later than the later to occur of (i) ninety (90) days after the Effective Date and (ii) a date specified by a written notice to the Company by Demand Stockholders holding at least a majority of the Registerable Securities, and thereafter to use its commercially reasonable best efforts to cause to be declared effective by the SEC as soon as reasonably practicable. In addition, from time to time, the Demand Stockholders may request that additional Registrable Securities be registered for resale by the Company. Subject to certain limitations, the Demand Stockholders also have the right to request that the Company facilitate the resale of Registrable Securities pursuant to firm commitment underwritten public offerings.

The Registration Rights Agreement contains other customary terms and conditions, including, without limitation, provisions with respect to suspensions of the Company's registration obligations pursuant to the Registration Rights Agreement and indemnification.

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

The following discussion is intended to assist in understanding our results of operations for the three and nine months ended September 30, 2019 and 2018 and should be read in conjunction with our unaudited condensed consolidated financial statements and the notes thereto included in this Quarterly Report on Form 10-Q and with the consolidated financial statements, notes and management's discussion and analysis of financial condition and results of operations included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2018.

Statements in this discussion may be forward-looking. These forward-looking statements involve risks and uncertainties, including those discussed below, which could cause actual results to differ from those expressed. For more information, see "Special note regarding forward-looking statements."

We are an independent energy company focused on the acquisition, production, exploration and development of onshore liquids-rich oil and natural gas assets in the United States. During 2017, we acquired certain properties in the Delaware Basin and divested our assets located in the Williston Basin in North Dakota (the Williston Divestiture) and in the El Halcón area of East Texas (the El Halcón Divestiture). As a result, our properties and drilling activities are currently focused in the Delaware Basin of West Texas, where we have an extensive drilling inventory that we believe offers attractive economics.

During the first nine months of 2019, production averaged 17,209 Boe/d compared to average daily production of 12,795 Boe/d during the first nine months of 2018. Our average daily oil and natural gas production increased in the first nine months of 2019 when compared to the same period in the prior year due to the acquisition of properties in West Quito Draw and our drilling activities in Monument Draw and West Quito Draw. For the nine months ended September 30, 2019, we drilled and cased 15 gross (13.8 net) wells, completed 15 gross (13.9 net) wells, and put online 14 gross (13.5 net) wells.

Our financial results depend upon many factors, but are largely driven by the volume of our oil and natural gas production and the price that we receive for that production. Our production volumes will decline as reserves are depleted unless we expend capital in successful development and exploration activities or acquire properties with existing production. The amount we realize for our production depends predominantly upon commodity prices, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, transportation take-away capacity constraints, inventory storage levels, basis differentials and other factors. Accordingly, finding and developing oil and natural gas reserves at economical costs is critical to our long-term success.

Oil and natural gas prices are inherently volatile and sustained lower commodity prices could have a material impact upon our full cost ceiling test calculation. The ceiling test calculation dictates that we use the unweighted arithmetic average price of crude oil and natural gas as of the first day of each month for the 12-month period ending at the balance sheet date. Using the crude oil price for October 1, 2019 of $53.98 per barrel, and holding it constant for two months to create a trailing 12-month period of average prices, that is more reflective of recent price trends, our ceiling test limitation would have generated an additional impairment of $45.0 million holding all other inputs and factors constant. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties to our full cost pool, capital spending and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

On August 2, 2019, we entered into a Restructuring Support Agreement (the Restructuring Support Agreement) with certain holders of our 6.75% senior unsecured notes due 2025 (the Unsecured Senior Noteholders). On August 7, 2019, we filed voluntary petitions for relief under chapter 11 of the United States Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of Texas (the Bankruptcy Court) to effect a prepackaged plan of reorganization (the Plan) as contemplated in the Restructuring Support Agreement. On September 24, 2019, the Bankruptcy Court entered an order confirming the Company's Plan and on October 8, 2019, we emerged from chapter 11 bankruptcy.

As a component of the Restructuring Support Agreement (i) each Unsecured Senior Noteholder was offered the right to purchase its pro rata share of New Common Shares for an aggregate purchase price of $150,150,000 (the Senior Noteholder Rights Offering) and (ii) each existing common stockholder was offered (subject to the Existing Equity Cash Out) the right to purchase its pro rata share of New Common Shares for an aggregate purchase price of up to $14,850,000 (the Existing Equity Interests Rights Offering, and together with the Senior Noteholder Rights Offering, the Equity Rights Offerings), in each case, at a price per share equal to a 26% discount to the value of the New Common Shares based an assumed total enterprise value of $425.0 million. Certain of the Unsecured Senior Noteholders backstopped the Senior Noteholder Rights Offering and received as consideration (the Backstop Commitment Premium) New Common Shares equal to 6% of the aggregate amount of the Senior Noteholder Rights Offering subject to dilution by New Common Shares issued in connection with a management incentive plan and the Warrants. If the backstop agreement had been terminated, we would have been obligated to a cash payment equal to 6% of the aggregate amount of the Senior

Noteholder Rights Offering. We used the proceeds of the Equity Rights Offerings to (i) provide additional liquidity for working capital and general corporate purposes, (ii) pay all reasonable and documented restructuring expenses, and (iii) fund Plan distributions.

Under the Restructuring Support Agreement, each existing common stockholder (subject to the Existing Equity Cash Out) will be issued a series of warrants exercisable in cash for a three year period subsequent to the effective date of the Plan (Warrants). The Warrants were issued with strike prices based upon stipulated rate-of-return levels achieved by the Unsecured Senior Noteholders. The Warrants represents cumulatively represent 30% of the New Common Shares issued pursuant to the Plan.

On the Effective Date, pursuant to the terms of the Plan, all shares of our predecessor company were cancelled and we filed an amended and restated certificate of incorporation with the Delaware Secretary of State and adopted amended and restated bylaws. Pursuant to the amended and restated certificate of incorporation, the number of authorized shares of common stock which we have the authority to issue was reduced from 1,001,000,000 to 101,000,000. Of the 101,000,000 authorized shares, 100,000,000 are common stock, par value $0.0001 per share and 1,000,000 are preferred stock, par value $0.0001 per share.

On the Effective Date, pursuant to the terms of the Plan and the confirmation order, we issued:

Our common stock was previously listed on the New York Stock Exchange (NYSE) under the symbol "HK." As a result of our failure to satisfy the continued listing requirements of the NYSE, on July 22, 2019, our common stock was delisted from the NYSE. We are not currently listed on a national securities exchange; however, we endeavor to be relisted and commence trading on a national securities exchange prior to December 31, 2019.

On the Effective Date, by operation of the Plan and the confirmation order, all warrants of our predecessor company were cancelled and we entered into a warrant agreement (the Warrant Agreement) with Broadridge Corporate Issuer Solutions, Inc., pursuant to which we issued three series of warrants (the Series A Warrants, the Series B Warrants and the Series C Warrants and together, the Warrants, and the holders thereof, the Warrant Holders), on a pro rata basis to pre-emergence holders of our Existing Equity Interests pursuant to the Plan.

Each Warrant represents the right to purchase one share of New Common Shares at the applicable exercise price, subject to adjustment as provided in the Warrant Agreement and as summarized below.

On the Effective Date, we issued (i) Series A Warrants to purchase an aggregate of 1,798,322 shares of New Common Stock, with an initial exercise price of $40.17 per share, (ii) Series B Warrants to purchase an aggregate of 2,247,985 shares of New Common Stock, with an initial exercise price of $48.28 per share and (iii) Series C Warrants to purchase an aggregate of 2,890,271 shares of New Common Stock, with an initial exercise price of $60.45 per share. Each series of Warrants issued under the Warrant Agreement has a three-year term, expiring on October 8, 2022. The strike price of each series of Warrants issued under the Warrant Agreement increases monthly, as provided in the Warrant Agreement.

The Warrants do not grant the Warrant Holder any voting or control rights or dividend rights, or contain any negative covenants restricting the operation of our business.

On the Effective Date, we and the other signatories thereto (the Demand Stockholders), entered into a registration rights agreement (the Registration Rights Agreement), pursuant to which, subject to certain conditions and limitations, we agreed to file with the SEC a registration statement concerning the resale of the registrable shares of our New Common Shares held by Demand Stockholders (the Registrable Securities), as soon as reasonably practicable but in no event later than the later to occur of (i) ninety (90) days after the Effective Date and (ii) a date specified by a written notice to us by Demand Stockholders holding at least a majority of the Registerable Securities, and thereafter to use its commercially reasonable best efforts to cause to be declared effective by the SEC as soon as reasonably practicable. In addition, from time to time, the Demand Stockholders may request that additional Registrable Securities be registered for resale by us. Subject to certain limitations, the Demand Stockholders also have the right to request that we facilitate the resale of Registrable Securities pursuant to firm commitment underwritten public offerings.

The Registration Rights Agreement contains other customary terms and conditions, including, without limitation, provisions with respect to suspensions of our registration obligations pursuant to the Registration Rights Agreement and indemnification.

Upon emergence from chapter 11 bankruptcy, we qualified for and adopted fresh-start accounting in accordance with the provisions set forth in ASC 852 as (i) the reorganization value of our assets immediately prior to the date of confirmation was less than the post-petition liabilities and allowed claims, and (ii) the holders of the existing voting shares of the predecessor entity received less than 50% of the voting shares of the emerging entity. Refer to "Reorganization" above for the terms of the Plan. Fresh-start accounting requires us to present our assets, liabilities, and equity as if we were a new entity upon emergence from bankruptcy. Our new entity will be referred to as "successor" or "successor company." However, we will continue to present financial information for any periods before adoption of fresh-start accounting for our predecessor company. Our predecessor and successor companies may lack comparability, as required in ASC 205, Presentation of Financial Statements (ASC 205). ASC 205 states financial statements are required to be presented comparably from year to year, with any exceptions to comparability clearly disclosed. Therefore, "black-line" financial statements are required to be presented to distinguish between the predecessor and successor companies.

value of our long-term debt and stockholders' equity less cash. The process of estimating the fair value of our assets, liabilities and equity upon emergence is currently ongoing and, therefore, such amounts have not yet been finalized. In support of the Plan, the enterprise value of our successor company was estimated and approved by the Bankruptcy Court to be in the range of $425.0 million and $475.0 million.

On the Effective Date, we entered into a senior secured revolving credit agreement with Bank of Montreal, as administrative agent, and certain other financial institutions party thereto, as lenders, which refinanced the DIP Facility and Senior Credit Agreement. The Exit Facility provides for a $750.0 million senior secured reserve-based revolving credit facility. The Exit Facility has an initial borrowing base of $275.0 million and on the Effective Date, we made an initial draw of $130.0 million. A portion of the Exit Facility, in the amount of $50 million, is available for the issuance of letters of credit. The maturity date of the Exit Facility is October 8, 2024. The first redetermination will be in the spring of 2020 and redeterminations will occur semi-annually thereafter, with the lenders and the Company each having the right to one interim unscheduled redetermination between any two consecutive semi-annual redeterminations. The borrowing base takes into account the estimated value of the Company's oil and natural gas properties, proved reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria. Amounts outstanding under the Exit Facility bear interest at specified margins over the base rate of 1.00% to 2.00% for ABR-based loans or at specified margins over LIBOR of 2.00% to 3.00% for Eurodollar-based loans, which margins may be increased one-time by not more than 50 basis points per annum if necessary in order to successfully syndicate the Exit Facility, which is currently in process. These margins fluctuate based on the Company's utilization of the facility.

We may elect, at our option, to prepay any borrowings outstanding under the Exit Credit Agreement without premium or penalty (except with respect to any break funding payments which may be payable pursuant to the terms of the Exit Credit Agreement). We may be required to make mandatory prepayments of the Loans under the Exit Facility in connection with certain borrowing base deficiencies, including deficiencies which may arise in connection with a borrowing base redetermination, an asset disposition or swap terminations attributable in the aggregate to more than ten percent (10%) of the then-effective borrowing base. Amounts outstanding under the Exit Credit Agreement are guaranteed by our direct and indirect subsidiaries and secured by a security interest in substantially all of our assets and the assets of our subsidiaries.

In connection with the chapter 11 proceedings and pursuant to an order of the Bankruptcy Court dated August 9, 2019 (the Interim Order), we entered into a Junior Secured Debtor-In-Possession Credit Agreement (the DIP Credit Agreement) with the Unsecured Senior Noteholders party thereto from time to time as lenders (the DIP Lenders) and Wilmington Trust, National Association, as administrative agent.

Under the DIP Credit Agreement, the DIP Lenders made available a $35.0 million debtor-in-possession junior secured term credit facility (the DIP Facility), of which $25.0 million was extended as an initial loan and the remainder of which was drawn on September 5, 2019. The DIP Facility was refinanced with a $750.0 million exit senior secured reserve-based revolving credit facility on October 8, 2019. At September 30, 2019, we had $35.0 million of indebtedness outstanding under the DIP Facility.

We used the proceeds of the DIP Facility to, among other things, (i) provide working capital and other general corporate purposes, including to finance capital expenditures and make certain interest payments as and to the extent set forth in the Interim Order and/or the final order, as applicable, of the Bankruptcy Court and in accordance with our budget delivered pursuant to the DIP Credit Agreement, (ii) pay fees and expenses related to the transactions contemplated by the DIP Credit Agreement in accordance with such budget and (iii) cash collateralize any letters of credit.

The DIP Facility was secured by (i) a junior secured perfected security interest on all assets that secure the Senior Credit Agreement and (ii) a senior secured perfected security interest on all our unencumbered assets and any subsidiary guarantors. The security interests and liens were further subject to certain carve-outs and permitted liens, as set forth in the DIP Credit Agreement.

On October 8, 2019, borrowings outstanding under the Senior Credit Agreement were repaid and refinanced with proceeds from the Equity Rights Offerings and borrowings under the Exit Facility. During the chapter 11 proceedings, amounts outstanding under the Senior Credit Agreement bore interest at a rate per annum equal to 2.0% plus the applicable interest rate in effect.

On May 9, 2019, we entered into the Eighth Amendment, Consent and Waiver to Amended and Restated Senior Secured Credit Agreement (the Eighth Amendment) which, among other things, (i) temporarily waived any default or event of default directly resulting from the potential Leverage Ratio Default (as defined in the Eighth Amendment) for the fiscal quarter ended March 31, 2019, (ii) increased interest margins to 1.75% to 2.75% for ABR-based loans and 2.75% to 3.75% for Eurodollar-based loans, (iii) reduced our Consolidated Cash Balance (as defined in the Eighth Amendment) to $5.0 million, and (iv) provided for periodic reporting of projected cash flows and accounts payable agings to the lenders. Under the Eighth Amendment, the waiver would have terminated and an Event of Default (as defined in the Senior Credit Agreement) would have occurred on August 1, 2019. On July 31, 2019, we entered into the Waiver to Amended and Restated Senior Secured Credit Agreement, pursuant to which the termination date for the waiver granted by the Eighth Amendment was extended to August 8, 2019.

On February 28, 2019, the lenders party to our Senior Credit Agreement issued a consent (the Severance and Office Payments Consent) to us whereby Severance Payments and Office Payments (as defined in the Severance and Office Payments Consent) may exceed the maximum level allowed for adding back non-recurring expenses and charges in the definition of EBITDA (as defined in the Senior Credit Agreement) when calculating the ratio of Consolidated Total Net Debt to EBITDA (as defined in the Senior Credit Agreement) for the fiscal quarter ending March 31, 2019.

On February 15, 2019, we entered into the Seventh Amendment (the Seventh Amendment) to the Senior Credit Agreement which, among other things, provided for (i) the use of annualized financial data in determining EBITDA (as defined in the Senior Credit Agreement) for the fiscal quarters ending March 31, 2019, June 30, 2019 and September 30, 2019 and (ii) amended the ratio of Consolidated Total Net Debt (as defined in the Senior Credit Agreement) to EBITDA to be (a) 5.00 to 1.0 for the fiscal quarter ending March 31, 2019, (b) 4.75 to 1.0 for the fiscal quarter ending June 30, 2019, (c) 4.5 to 1.0 for the fiscal quarter ending September 30, 2019, (d) 4.25 to 1.0 for the fiscal quarter ending December 31, 2019, and (e) 4.0 to 1.0 for the fiscal quarter ending March 31, 2020 and any fiscal quarter thereafter.

On November 6, 2018, the lenders party to our Senior Credit Agreement issued a consent (the H2S Consent) to us whereby H2S Expenses (as defined in the H2S Consent) may exceed the maximum level allowed for adding back non-recurring expenses and charges in the definition of EBITDA (as defined in the Senior Credit Agreement) when calculating the ratio of Consolidated Total Net Debt to EBITDA (as defined in the Senior Credit Agreement) for the fiscal quarters ending September 30, 2018, December 31, 2018 and March 31, 2019.

On December 20, 2018, we sold our water infrastructure assets located in the Delaware Basin (the Water Assets) to WaterBridge Resources LLC (the Purchaser) for an adjusted purchase price of $210.9 million in cash (the Water Infrastructure Divestiture) at closing. The effective date of the transaction was October 1, 2018. Additional incentive payments of up to $25.0 million per year for the years from 2019 to 2023 were available subject to our ability to meet certain annual incentive thresholds relating to the number of wells connected to the Water Assets per year. In August 2019, we and the Purchaser agreed to terminate the incentive payments.

Upon closing, we dedicated all of the produced water from our oil and natural gas wells within our Monument Draw, Hackberry Draw and West Quito Draw operating areas to the Purchaser. There are no drilling or throughput commitments associated with the Water Infrastructure Divestiture. The Purchaser will receive a market price, subject to annual adjustments for inflation, in exchange for the transportation, disposal and treatment of such produced water, and the Purchaser will receive a market price for the supply of freshwater and recycled produced water provided to us.

Our near-term capital spending requirements are expected to be funded with cash and cash equivalents on hand, cash flows from operations, and borrowings under our Exit Facility. On the Effective Date, we entered into a senior secured revolving credit agreement with Bank of Montreal, as administrative agent, and certain other financial institutions party thereto, as lenders, which refinanced the DIP Facility and Senior Credit Agreement. The Exit Facility provides for a $750 million senior secured reserve-based revolving credit facility, with an initial borrowing base of $275 million. On the Effective Date, we made an initial draw on the Exit Facility of $130.0 million. The first redetermination will be in the spring of 2020 and redeterminations will occur semi-annually thereafter, with the lenders and the Company each having the right to one interim unscheduled redetermination between any two consecutive semi-annual redeterminations. The borrowing base takes into account the estimated value

of the Company's oil and natural gas properties, proved reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria. The effect of these and other factors may result in an increase or a decrease in the amount of our borrowing base. A significant reduction in our borrowing base as a result of a redetermination or otherwise may negatively impact our liquidity and our ability to fund our operations. The Exit Credit Agreement contains certain financial covenants, including the maintenance of (i) a Total Net Indebtedness Leverage Ratio (as defined in the Exit Credit Agreement) not to exceed 4.00:1.00, determined as of each four fiscal quarter periods and commencing with the fiscal quarter ending March 31, 2020 and (ii) a Current Ratio (as defined in the Exit Credit Agreement) not to be less than 1.00:1.00, commencing with the fiscal quarter ending March 31, 2020.

Our strategic decision to transform into a pure-play, single basin company focused on the Delaware Basin in West Texas resulted in us divesting our producing properties located in other areas and acquiring primarily undeveloped acreage in the Delaware Basin. Our drilling activities since acquiring the assets required significant capital expenditure outlays to replace lost production and related EBITDA. These and other factors adversely impacted our ability to comply with our debt covenants under the Senior Credit Agreement by reducing our production, reserves and EBITDA on a current and a pro forma historical basis, while making us more susceptible to fluctuations in performance and compliance more challenging. In addition, we encountered certain operational challenges that impacted our ability to comply, including recently, elevated levels of hydrogen sulfide in the natural gas produced from our Monument Draw wells, limited and expensive treatment and transportation options, as well as severance payments associated with personnel changes.

We have in the past obtained amendments to the covenants under our credit agreements under circumstances where we anticipated that it might be challenging for us to comply with our financial covenants for a particular period of time. As part of our plan to manage liquidity risks, we scaled back our capital expenditures budget, focused our drilling program on our highest return projects, continued to explore opportunities to divest non-core properties, entered into a Restructuring Support Agreement to restructure our indebtedness and, on August 7, 2019, filed a voluntary petition for relief under chapter 11 of the United States Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of Texas to pursue a prepackaged plan of reorganization. On September 24, 2019, the Bankruptcy Court entered an order confirming the Company's plan of reorganization and on October 8, 2019, we emerged from chapter 11 bankruptcy.

Our future capital resources and liquidity depend, in part, on our success in developing our leasehold interests, growing our reserves and production and finding additional reserves. Cash is required to fund capital expenditures necessary to offset inherent declines in our production and proven reserves, which is typical in the capital-intensive oil and natural gas industry. We therefore continuously monitor our liquidity and evaluate our development plans in light of a variety of factors, including, but not limited to, our cash flows, capital resources, acquisition opportunities and drilling successes. We strive to maintain financial flexibility while pursuing our drilling plans and may access capital markets, pursue joint ventures, sell assets and engage in other transactions as necessary to, among other things, maintain borrowing capacity, facilitate drilling on our undeveloped acreage position and permit us to selectively expand our acreage. Our ability to complete such transactions and maintain or increase our borrowing base is subject to a number of variables, including our level of oil and natural gas production, proved reserves and commodity prices, the amount and cost of our other indebtedness, as well as various economic and market conditions that have historically affected the oil and natural gas industry. Even if we are otherwise successful in growing our proved reserves and production, if oil and natural gas prices decline for a sustained period of time, our ability to fund our capital expenditures, complete acquisitions, reduce debt, meet our financial obligations and become profitable may be materially impacted. While we use derivative instruments to provide partial protection against declines in oil and natural gas prices, the total volumes we hedge varies from period

to period based on our view of current and future market conditions. Our hedge policies and objectives may change significantly as our operational profile changes and/or commodities prices change. We do not enter into derivative contracts for speculative trading purposes.

During the nine months ended September 30, 2019, cash and cash equivalents on hand supplemented with borrowings under our Senior Credit Agreement and DIP Facility were used to fund our drilling and completion program. During the nine months ended September 30, 2018, cash generated by financing activities was used to fund the acquisitions of acreage in our Monument Draw and West Quito Draw areas, as well as our drilling and completion program. See "Results of Operations" for a review of the impact of prices and volumes on sales.

Net increase (decrease) in cash and cash equivalents is summarized as follows (in thousands):

Operating Activities. Net cash flows used in operating activities for the nine months ended September 30, 2019 were $33.2 million. Net cash flows provided by operating activities were $36.7 million for the nine months ended September 30, 2018.

Operating cash flows for the nine months ended September 30, 2019 decreased from the comparable prior year period due to increases in our operating expenses, primarily severances paid to executives, reorganization costs, and third party water hauling and disposal costs.

Operating cash flows for the nine months ended September 30, 2018 decreased from the comparable prior year period primarily due to our divestitures in 2017, in which we divested non-core producing properties in other areas for primarily undeveloped acreage in the Delaware Basin. This decrease was partially offset by $30.8 million of proceeds related to a monetization of basis swaps that occurred in the nine months ended September 30, 2018.

Investing Activities. Net cash flows used in investing activities were approximately $254.4 million and $778.1 million for the nine months ended September 30, 2019 and 2018, respectively.

During the nine months ended September 30, 2019, we spent $167.2 million on oil and natural gas expenditures, of which $158.6 million related to drilling and completion costs. We also spent approximately $85.6 million on capital expenditures related to our other operating property and equipment, primarily to develop our natural gas treating equipment and our oil and natural gas gathering infrastructure.

During the first nine months of 2018, we incurred cash expenditures of $333.5 million on acquisition activities, the majority of which related to the acquisition of the West Quito Draw Properties and the purchase of the Northern Tract of the Ward County Assets. Additionally, we spent $369.3 million on oil and natural gas capital expenditures, of which $342.8 million related to drilling and completion costs. We also spent approximately $79.4 million on capital expenditures related to our other operating property and equipment, primarily to develop our water recycling facilities and gas gathering infrastructure.

Financing Activities. Net cash flows provided by financing activities were $257.8 million and $317.5 million for the nine months ended September 30, 2019 and 2018, respectively.

During the nine months ended September 30, 2019, net borrowings of $35.0 million under our DIP Facility and $223.2 million under our Senior Credit Agreement were used to fund our drilling and completions program, as well as the development of our natural gas treating infrastructure and our oil and natural gas gathering infrastructure.

During the first nine months of 2018, we issued an additional $200.0 million aggregate principal amount of our 6.75% senior notes due 2025. Proceeds from the private placement were approximately $202.4 million after deducting initial purchasers' premiums, commissions and offering expenses. Additionally, we sold 9.2 million shares of common stock in a public offering at a price of $6.90 per share. The net proceeds from the offering were approximately $60.4 million after deducting underwriters' discounts and offering expenses.

There were no material changes outside the ordinary course of business to our commitments under contractual obligations from those disclosed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2018.

Our discussion and analysis of our financial condition and results of operations are based upon the unaudited condensed consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. Preparation of these unaudited condensed consolidated financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. There have been no material changes to our critical accounting policies from those described in our Annual Report on Form 10-K for the fiscal year ended December 31, 2018, except as described below.

We utilized the discrete effective tax rate method as allowed by ASC 740, Income Taxes, to calculate our interim income tax provision for the three and nine months ended September 30, 2019. See Item 1. Condensed Consolidated Financial Statements (Unaudited)—Note 1, "Financial Statement Presentation," for details.

We reported a net loss of $63.3 million and $81.8 million for the three months ended September 30, 2019 and 2018, respectively. The table included below sets forth financial information for the periods presented.

	Three Months Ended September 30,

In thousands (except per unit and per Boe amounts)	2019			2018			Change
Net income (loss)	$	(63,284	)	$	(81,837	)	$	18,553
Operating revenues:
Oil		46,275			53,918			(7,643	)
Natural gas		301			1,407			(1,106	)
Natural gas liquids		3,987			5,920			(1,933	)
Other		246			350			(104	)
Operating expenses:
Production:
Lease operating		11,958			5,275			6,683
Workover and other		1,566			1,478			88
Taxes other than income		3,012			3,557			(545	)
Gathering and other		10,147			18,404			(8,257	)
Restructuring		3,223			—			3,223
General and administrative:
General and administrative		21,701			15,308			6,393
Stock-based compensation		(2,278	)		4,423			(6,701	)
Depletion, depreciation and accretion:
Depletion—Full cost		18,036			18,170			(134	)
Depreciation—Other		2,371			2,046			325
Accretion expense		105			94			11
Full cost ceiling impairment		45,568			—			45,568
(Gain) loss on sale of oil and natural gas properties		—			1,331			(1,331	)
(Gain) loss on sale of Water Assets		(164	)		—			(164	)
Other income (expenses):
Net gain (loss) on derivative contracts		13,457			(60,406	)		73,863
Interest expense and other		(10,547	)		(12,940	)		2,393
Reorganization items		(1,758	)		—			(1,758	)
Production:
Oil—MBbls		863			980			(117	)
Natural Gas—MMcf		1,924			1,040			884
Natural gas liquids—MBbls		333			190			143
Total MBoe⁽¹⁾		1,517			1,344			173
Average daily production—Boe/d⁽¹⁾		16,489			14,609			1,880
*Average price per unit⁽²⁾***:
Oil price—Bbl	$	53.62		$	55.02		$	(1.40	)
Natural gas price—Mcf		0.16			1.35			(1.19	)
Natural gas liquids price—Bbl		11.97			31.16			(19.19	)
Total per Boe⁽¹⁾		33.33			45.57			(12.24	)
Average cost per Boe:
Production:
Lease operating	$	7.88		$	3.92		$	3.96
Workover and other		1.03			1.10			(0.07	)
Taxes other than income		1.99			2.65			(0.66	)
Gathering and other		6.69			13.69			(7.00	)
Restructuring		2.12			—			2.12
General and administrative:
General and administrative		14.31			11.39			2.92
Stock-based compensation		(1.50	)		3.29			(4.79	)
Depletion		11.89			13.52			(1.63	)

Oil, natural gas and natural gas liquids revenues were $50.6 million and $61.2 million for the three months ended September 30, 2019 and 2018, respectively. For the three months ended September 30, 2019 and 2018, production averaged 16,489 Boe/d and 14,609 Boe/d, respectively. Our average daily oil and natural gas production increased in the three months ended September 30, 2019 when compared to the same period in the prior year due to the acquisition of properties in West Quito Draw and our drilling activities in Monument Draw and West Quito Draw. Average realized prices (excluding the effects of hedging arrangements) were $33.33 per Boe and $45.57 per Boe for the three months ended September 30, 2019 and 2018, respectively. The amount we realized for our production depends predominantly upon commodity prices, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, transportation take-away capacity constraints, inventory storage levels, quality of production, basis differentials and other factors.

Lease operating expenses were $12.0 million and $5.3 million for the three months ended September 30, 2019 and 2018, respectively. On a per unit basis, lease operating expenses were $7.88 per Boe and $3.92 per Boe for the three months ended September 30, 2019 and 2018, respectively. The increase in lease operating expenses from 2018 levels results from higher third party water hauling and disposal costs resulting from our Water Infrastructure Divestiture and an increase in our inventory of wells due to our drilling and acquisition activities.

Workover and other expenses were $1.6 million and $1.5 million for the three months ended September 30, 2019 and 2018, respectively. On a per unit basis, workover and other expenses were $1.03 per Boe and $1.10 per Boe for the three months ended September 30, 2019 and 2018, respectively.

Taxes other than income were $3.0 million and $3.6 million for the three months ended September 30, 2019 and 2018, respectively. Most production taxes are based on realized prices at the wellhead. As revenues or volumes from oil and natural gas sales increase or decrease, production taxes on these sales also increase or decrease. On a per unit basis, taxes other than income were $1.99 per Boe and $2.65 per Boe for the three months ended September 30, 2019 and 2018, respectively.

Gathering and other expenses were $10.1 million and $18.4 million for the three months ended September 30, 2019 and 2018, respectively. Gathering and other expenses include gathering fees paid to third parties on our oil and natural gas production, operating expenses of our oil and gas gathering infrastructure, gas treating fees, rig stacking charges and other. Approximately $2.5 million and $1.4 million of expenses incurred for the three months ended September 30, 2019 and 2018, respectively, relate to gathering and marketing fees paid to third parties on our oil and natural gas production. Approximately $7.3 million and $17.4 million of expenses for the three months ended September 30, 2019 and 2018, respectively, relate to operating expenses on our oil and gas gathering infrastructure and in the 2018 period, on our water recycling and disposal facilities. Included in the three months ended September 30, 2018 are $13.7 million of wellhead-level costs to remove hydrogen sulfide from natural gas produced from our Monument Draw properties. In April 2019, we installed a hydrogen sulfide (H2S) treating plant that more efficiently removes hydrogen sulfide from our produced natural gas and reduces our reliance on expensive wellhead-level treating. Also included are $0.9 million of rig stacking charges for the three months ended September 30, 2018.

Restructuring expense was approximately $3.2 million and zero during the three months ended September 30, 2019 and 2018, respectively. During the three months ended September 30, 2019, senior executives resigned from their positions. These were considered terminations without cause under their respective employment agreements, which entitled them to certain benefits. Additionally during the period, we made the decision to consolidate into one corporate office located in Houston, Texas in an effort to improve efficiencies and go forward costs. The transition includes both severance and relocation costs as well as incremental costs associated with hiring new employees to replace key positions.

General and administrative expense was approximately $21.7 million and $15.3 million for the three months ended September 30, 2019 and 2018, respectively. The increase in general and administrative expenses results from increases in professional fees associated with the efforts to restructure our indebtedness. On a per unit basis, general and administrative expenses were $14.31 per Boe and $11.39 per Boe for the three months ended September 30, 2019 and 2018, respectively.

Stock-based compensation expense was a credit of $2.3 million and expense of $4.4 million for the three months ended September 30, 2019 and 2018, respectively. During the three months ended September 30, 2019, senior executives resigned from their positions. In accordance with the terms of these senior executives' employment agreements, unvested stock options and unvested shares of restricted stock were modified to vest immediately upon termination. For the three months ended September 30, 2019, we recognized an incremental reduction to stock-based compensation expense of $1.1 million associated with these modifications. Stock-based compensation expense also decreased in the current period due to a reduction in our workforce.

Depletion for oil and natural gas properties is calculated using the unit of production method, which depletes the capitalized costs of evaluated properties plus future development costs based on the ratio of production for the current period to total reserve volumes of evaluated properties as of the beginning of the period. Depletion expense was $18.0 million and $18.2 million for the three months ended September 30, 2019 and 2018, respectively. On a per unit basis, depletion expense was $11.89 per Boe and $13.52 per Boe for the three months ended September 30, 2019 and 2018, respectively. The decrease in the depletion rate per Boe from 2018 levels is primarily attributable to decreases in our depletable base due to the full cost ceiling impairments.

Under the full cost method of accounting, sales of oil and gas properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless the adjustment significantly alters the relationship between capitalized costs and proved reserves. If the Williston Divestiture was accounted for as an adjustment of capitalized costs with no gain or loss recognized, the adjustment would have significantly altered the relationship between capitalized costs and proved reserves at the time of the transaction. Accordingly, we recognized a reduction to the gain on the sale of the oil and natural gas properties associated with the Williston Divestiture of $1.3 million during the three months ended September 30, 2018, as a result of customary post-closing adjustments. The carrying value of the properties sold was determined by allocating total capitalized costs within the full cost pool between properties sold and properties retained based on their relative fair values.

On December 20, 2018, we sold our water infrastructure assets located in the Delaware Basin for a total adjusted purchase price of $210.9 million. We recognized a cumulative $115.4 million gain on the sale which includes the $0.2 million increase in the three months ended September 30, 2019 due to customary closing adjustments.

We enter into derivative commodity instruments to economically hedge our exposure to price fluctuations on our anticipated oil, natural gas and natural gas liquids production. Consistent with prior years, we have elected not to designate any positions as cash flow hedges for accounting purposes, and accordingly, we recorded the net change in the mark-to-market value of these derivative contracts in our unaudited condensed consolidated statements of operations. At September 30, 2019, we had a $19.4 million derivative asset, $15.3 million of which was classified as current and we had a $8.5 million derivative liability, $6.8 million of which was classified as current associated with these contracts. We recorded a net derivative gain of $13.5 million ($11.6 million net unrealized gain and $1.9 million net realized gain on settled and early terminated contracts) for the three months ended September 30, 2019 compared to a net derivative loss of $60.4 million ($50.8 million net unrealized loss and $9.6 million net realized loss on settled and early terminated contracts), in the same period in 2018.

Interest expense and other was $10.5 million and $12.9 million for the three months ended September 30, 2019 and 2018, respectively. Interest expense increased during the three months ended September 30, 2019 as compared to the prior year period due to higher outstanding borrowings and interest rates under our Senior Credit Agreement and DIP Facility, as well as fees paid in 2019 associated with consents and amendments to our Senior Credit Agreement.

We recorded a net loss on reorganization items of $1.8 million for the three months ended September 30, 2019 which includes the following:

We reported a net loss of $1.0 billion and $100.7 million for the nine months ended September 30, 2019 and 2018, respectively. The table included below sets forth financial information for the periods presented.

	Nine Months Ended September 30,

In thousands (except per unit and per Boe amounts)	2019			2018			Change
Net income (loss)	$	(1,040,687	)	$	(100,709	)	$	(939,978	)
Operating revenues:
Oil		145,024			145,743			(719	)
Natural gas		107			5,286			(5,179	)
Natural gas liquids		13,229			14,623			(1,394	)
Other		743			613			130
Operating expenses:
Production:
Lease operating		39,617			15,504			24,113
Workover and other		5,580			4,795			785
Taxes other than income		9,213			9,812			(599	)
Gathering and other		36,057			30,782			5,275
Restructuring		15,148			128			15,020
General and administrative:
General and administrative		44,585			36,955			7,630
Stock-based compensation		(8,035	)		12,241			(20,276	)
Depletion, depreciation and accretion:
Depletion—Full cost		84,579			46,920			37,659
Depreciation—Other		6,026			5,252			774
Accretion expense		307			225			82
Full cost ceiling impairment		985,190			—			985,190
(Gain) loss on sale of oil and natural gas properties		—			7,235			(7,235	)
(Gain) loss on sale of Water Assets		3,618			—			3,618
Other income (expenses):
Net gain (loss) on derivative contracts		(34,332	)		(66,603	)		32,271
Interest expense and other		(37,606	)		(30,522	)		(7,084	)
Reorganization items		(1,758	)		—			(1,758	)
Income tax benefit (provision)		95,791			—			95,791
Production:
Oil—MBbls		2,723			2,468			255
Natural Gas—MMcf		6,381			3,009			3,372
Natural gas liquids—MBbls		911			523			388
Total MBoe⁽¹⁾		4,698			3,493			1,205
Average daily production—Boe⁽¹⁾		17,209			12,795			4,414
*Average price per unit⁽²⁾***:
Oil price—Bbl	$	53.26		$	59.05		$	(5.79	)
Natural gas price—Mcf		0.02			1.76			(1.74	)
Natural gas liquids price—Bbl		14.52			27.96			(13.44	)
Total per Boe⁽¹⁾		33.71			47.42			(13.71	)
Average cost per Boe:
Production:
Lease operating	$	8.43		$	4.44		$	3.99
Workover and other		1.19			1.37			(0.18	)
Taxes other than income		1.96			2.81			(0.85	)
Gathering and other		7.67			8.81			(1.14	)
Restructuring		3.22			0.04			3.18
General and administrative:
General and administrative		9.49			10.58			(1.09	)
Stock-based compensation		(1.71	)		3.50			(5.21	)
Depletion		18.00			13.43			4.57

Oil, natural gas and natural gas liquids revenues were $158.4 million and $165.7 million for the nine months ended September 30, 2019 and 2018, respectively. For the nine months ended September 30, 2019 and 2018, production averaged 17,209 Boe/d and 12,795 Boe/d, respectively. Our average daily oil and natural gas production increased in the first nine months of 2019 when compared to the same period in the prior year due to the acquisition of properties in West Quito Draw and our drilling activities in Monument Draw and West Quito Draw. Average realized prices (excluding the effects of hedging arrangements) were $33.71 per Boe and $47.42 per Boe for the nine months ended September 30, 2019 and 2018, respectively. The amount we realize for our production depends predominantly upon commodity prices, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, transportation take-away capacity constraints, inventory storage levels, quality of production, basis differentials and other factors.

Lease operating expenses were $39.6 million and $15.5 million for the nine months ended September 30, 2019 and 2018, respectively. On a per unit basis, lease operating expenses were $8.43 per Boe and $4.44 per Boe for the nine months ended September 30, 2019 and 2018, respectively. The increase in lease operating expenses from 2018 levels results from higher third party water hauling and disposal costs resulting from our Water Infrastructure Divestiture and an increase in our inventory of wells due to our drilling and acquisition activities.

Workover and other expenses were $5.6 million and $4.8 million for the nine months ended September 30, 2019 and 2018, respectively. The increased costs in 2019 relate to an increase in our inventory of wells due to our drilling and acquisition activities. On a per unit basis, workover and other expenses were $1.19 per Boe and $1.37 per Boe for the nine months ended September 30, 2019 and 2018, respectively.

Taxes other than income were $9.2 million and $9.8 million for the nine months ended September 30, 2019 and 2018, respectively. Most production taxes are based on realized prices at the wellhead. As revenues or volumes from oil and natural gas sales increase or decrease, production taxes on these sales also increase or decrease. On a per unit basis, taxes other than income were $1.96 per Boe and $2.81 per Boe for the nine months ended September 30, 2019 and 2018, respectively.

Gathering and other expenses were $36.1 million and $30.8 million for the nine months ended September 30, 2019 and 2018, respectively. Gathering and other expenses include gathering fees paid to third parties on our oil and natural gas production, operating expenses of our oil and gas gathering infrastructure, gas treating fees, rig stacking charges and other. Approximately $9.6 million and $3.8 million for the nine months ended September 30, 2019 and 2018, respectively, relate to gathering and marketing fees paid to third parties on our oil and natural gas production. Approximately $24.8 million and $26.2 million of expenses for the nine months ended September 30, 2019 and 2018, respectively, relate to operating expenses on our oil and gas gathering infrastructure and in the 2018 period, on our water recycling and disposal facilities. Included in the nine months ended September 30, 2019 and 2018 are $10.9 million and $14.0 million, respectively, of wellhead-level costs to remove hydrogen sulfide from natural gas produced from our Monument Draw properties. In April 2019, we installed an H2S treating plant that more efficiently removes hydrogen sulfide from our produced natural gas and reduces our reliance on expensive wellhead-level treating. Also included are $0.8 million and $1.9 million of rig stacking charges for the nine months ended September 30, 2019 and 2018, respectively.

Restructuring expense was approximately $15.1 million and $0.1 million during the nine months ended September 30, 2019 and 2018, respectively. During the nine months ended September 30, 2019, senior executives resigned from their positions. These were considered terminations without cause under their respective employment agreements, which entitled them to certain benefits. Additionally during the period, we made the decision to consolidate into one corporate office located in Houston, Texas in an effort to improve efficiencies and go forward costs. The transition includes both severance

and relocation costs as well as incremental costs associated with hiring new employees to replace key positions.

General and administrative expense was $44.6 million and $37.0 million for the nine months ended September 30, 2019 and 2018, respectively. The increase in general and administrative expenses results from increases in professional fees associated with the efforts to restructure our indebtedness totaling $9.9 million, offset by a reduction in our payroll and employee related benefits costs of $2.1 million due to a reduction in our workforce. On a per unit basis, general and administrative expenses were $9.49 per Boe and $10.58 per Boe for the nine months ended September 30, 2019 and 2018, respectively.

Stock-based compensation expense was a credit of $8.0 million and expense of $12.2 million for the nine months ended September 30, 2019 and 2018, respectively. During the nine months ended September 30, 2019, senior executives resigned from their positions. In accordance with the terms of these senior executives' employment agreements, unvested stock options and unvested shares of restricted stock were modified to vest immediately upon termination. For the nine months ended September 30, 2019, we recognized an incremental reduction to stock-based compensation expense of $9.5 million associated with these modifications. Stock-based compensation expense also decreased in the current period due to a reduction in our workforce.

Depletion for oil and natural gas properties is calculated using the unit of production method, which depletes the capitalized costs of evaluated properties plus future development costs based on the ratio of production for the current period to total reserve volumes of evaluated properties as of the beginning of the period. Depletion expense was $84.6 million and $46.9 million for the nine months ended September 30, 2019 and 2018, respectively. On a per unit basis, depletion expense was $18.00 per Boe and $13.43 per Boe for the nine months ended September 30, 2019 and 2018, respectively. The increase in the depletion rate per Boe from 2018 levels is attributed to decreases in our proved reserves, partially offset by decreases in our depletable base due to the full cost ceiling impairments in 2019.

Under the full cost method of accounting, we are required on a quarterly basis to determine whether the book value of our oil and natural gas properties (excluding unevaluated properties) is less than or equal to the "ceiling", based upon the expected after tax present value (discounted at 10%) of the future net cash flows from our proved reserves. Any excess of the net book value of our oil and natural gas properties over the ceiling must be recognized as a non-cash impairment expense. We recorded a full cost ceiling test impairment charge of $985.2 million for the nine months ended September 30, 2019. The ceiling test impairment at September 30, 2019 was driven by decreases in the first-day-of-the-month 12-month average price for crude oil used in the ceiling test calculation since June 30, 2019, when the first-day-of-month 12-month average price for crude oil was $61.45 per barrel. At June 30, 2019, we recorded a full cost ceiling impairment of $664.4 million. The ceiling test impairment at June 30, 2019 was primarily driven by our continued focus on our most economic area, Monument Draw. Accordingly, we transferred approximately $481.7 million of unevaluated property costs to the full cost pool as of June 30, 2019, the majority of which is associated with our Hackberry Draw area. At March 31, 2019, we recorded a full cost ceiling impairment of $275.2 million. The ceiling test impairment at March 31, 2019 was driven by a decrease in the first-day-of-the-month average price for crude oil used in the ceiling test calculation and our intent to expend capital only on our most economic areas. As such, we identified certain leases in the Hackberry Draw area with near-term expirations and transferred approximately $51.0 million of associated unevaluated property costs to the full cost pool during the three months ended March 31, 2019. Changes in commodity prices, production rates, levels of reserves, future development costs, transfers of unevaluated properties, and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

Under the full cost method of accounting, sales of oil and gas properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless the adjustment significantly alters the relationship between capitalized costs and proved reserves. If the Willison Divestiture was accounted for an adjustment of capitalized costs with no gain or loss recognized, the adjustment would have significantly altered the relationship between capitalized costs and proved reserves at the time of the transaction. Accordingly, we recognized a reduction to the gain on the sale of the oil and natural gas properties associated with the Williston Divestiture of $7.2 million during the nine months ended September 30, 2018, as a result of customary post-closing adjustments. The carrying value of the properties sold was determined by allocating total capitalized costs within the full cost pool between properties sold and properties retained based on their relative fair values.

On December 20, 2018, we sold our water infrastructure assets located in the Delaware Basin for a total adjusted purchase price of $210.9 million. We recognized a cumulative $115.4 million gain on the sale which includes the $3.6 million reduction in the nine months ended September 30, 2019 due to customary closing adjustments.

We enter into derivative commodity instruments to economically hedge our exposure to price fluctuations on our anticipated oil, natural gas and natural gas liquids production. Consistent with prior years, we have elected not to designate any positions as cash flow hedges for accounting purposes, and accordingly, we recorded the net change in the mark-to-market value of these derivative contracts in our unaudited condensed consolidated statements of operations. At September 30, 2019, we had a $19.4 million derivative asset, $15.3 million of which was classified as current and we had a $8.5 million derivative liability, $6.8 million of which was classified as current associated with these contracts. We recorded a net derivative loss of $34.3 million ($45.8 million net unrealized loss and $11.5 million net realized gain on settled and early terminated contracts) for the nine months ended September 30, 2019 compared to a net derivative loss of $66.6 million ($77.5 million net unrealized loss and $10.9 million net realized gain on settled and early terminated contracts), in the same period in 2018.

Interest expense and other was $37.6 million and $30.5 million for the nine months ended September 30, 2019 and 2018, respectively. Interest expense increased during the nine months ended September 30, 2019 as compared to the prior year period due to the issuance of additional 6.75% senior notes in February 2018, fees paid in 2019 associated with consents and amendments to our Senior Credit Agreement, and increased borrowings and interest rates under our Senior Credit Agreement and DIP Facility.

We recorded a net loss on reorganization items of $1.8 million for the nine months ended September 30, 2019 which includes the following:

We recorded an income tax benefit of $95.8 million using the discrete effective rate method for the nine months ended September 30, 2019, resulting from the reduction to the deferred tax liability generated by the impact of the full cost ceiling impairment on oil and natural gas properties and the deferred tax asset created by the tax loss from operations. The 8.4% effective tax rate for the nine months ended September 30, 2019 differs from the 21% statutory rate because of non-deductible executive compensation, non-deductible realized built in losses, and valuation allowances on deferred tax assets.

We discuss recently adopted and issued accounting standards in Item 1. Condensed Consolidated Financial Statements (Unaudited)—Note 1, "Financial Statement Presentation."

We are exposed to various risks, including energy commodity price risk, such as price differentials between the NYMEX commodity price and the index price at the location where our production is sold. When oil, natural gas and natural gas liquids prices decline significantly our ability to finance our capital budget and operations may be adversely impacted. We expect energy prices to remain volatile and unpredictable; therefore, we have designed a risk management policy which provides for the use of derivative instruments to provide partial protection against declines in oil, natural gas and natural gas liquids prices by reducing the risk of price volatility and the affect it could have on our operations. The types of derivative instruments that we typically utilize include costless collars, fixed-price swaps and basis swaps. The total volumes that we hedge through the use of derivative instruments varies from period to period, however, generally our objective is to hedge approximately 70% to 80% of our anticipated production for the next 18 to 24 months, when derivative contracts are available at terms (or prices) acceptable to us. Our hedge policies and objectives may change significantly as our operational profile changes and/or commodities prices change. We do not enter into derivative contracts for speculative trading purposes.

We are exposed to market risk on our open derivative contracts related to potential non-performance by our counterparties. It is our policy to enter into derivative contracts only with counterparties that are creditworthy institutions deemed by management as competitive market makers. As of September 30, 2019, we did not post collateral under any of our derivative contracts as they are secured under our Senior Credit Agreement or are uncollateralized trades. The filing of the voluntary petitions for relief under chapter 11 of the Bankruptcy Code described in in Item 1. Condensed Consolidated Financial Statements (Unaudited)—Note 2, "Reorganization," constituted an event of default under our derivatives contracts that gave the counterparties the option to terminate such contracts. Certain parties elected to terminate their contracts in August 2019 and we received approximately $0.1 million to settle a portion of the outstanding positions while other positions were novated for fees totaling $0.5 million. The remaining derivative contracts, including the novated positions, were secured on a super-priority pari passu basis with our Senior Credit Agreement during the bankruptcy process and remain in place following our chapter 11 proceedings. We account for our derivative activities under the provisions of Accounting Standards Codification 815, Derivatives and Hedging (ASC 815). ASC 815 establishes accounting and reporting that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value. Please refer to Item 1. Condensed Consolidated Financial Statements (Unaudited)—Note 9, "Derivative and Hedging Activities," for additional information.

The estimated fair values for financial instruments under Accounting Standards Codification 825, Financial Instruments (ASC 825) are determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash and cash equivalents, accounts receivable and accounts payable approximates their carrying value due to their short-term nature. See Item 1. Condensed Consolidated Financial Statements (Unaudited)—Note 8, "Fair Value Measurements," for additional information.

We are also exposed to market risk related to adverse changes in interest rates. Our interest rate risk exposure results primarily from fluctuations in short-term rates, which are LIBOR and ABR based and may result in reductions of earnings or cash flows due to increases in the interest rates we pay on these obligations.

At September 30, 2019, the principal amount of our debt was $258.2 million, all of which bears interest at floating and variable interest rates that, at our option, are tied to the prime rate or LIBOR. Fluctuations in market interest rates will cause our annual interest costs to fluctuate. At September 30, 2019, the weighted average interest rate on our variable rate debt was 9.47% per year. If the balance of our variable interest rate at September 30, 2019 were to remain constant, a 10% change in market interest rates would impact our cash flows by approximately $2.4 million per year.

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we evaluated the design and operation of our disclosure controls and procedures (as defined in rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, or the Exchange Act) as of September 30, 2019. On the basis of this review, our management, including our Chief Executive Officer and Chief Financial Officer, concluded that our disclosure controls and procedures are designed, and are effective, to give reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission and to ensure that information required to be disclosed in the reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, in a manner that allows timely decisions regarding required disclosure.

We did not have any change in our internal controls over financial reporting during the three months ended September 30, 2019 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Information regarding legal proceedings to which we are a party is set forth in Item 1. Condensed Consolidated Financial Statements (Unaudited)—Note 11, "Commitments and Contingencies," which is incorporated herein by reference.

There have been no changes to the risk factors described in our 2018 Annual Report on Form 10-K, for the fiscal year ended December 31, 2018, except as described below.

Our actual financial results may vary materially from the projections that we filed with the bankruptcy court in connection the confirmation of our plan of reorganization.

In connection with the disclosure statement we filed with the bankruptcy court, and the hearing to consider confirmation of our plan of reorganization, we prepared projected financial information to demonstrate to the bankruptcy court the feasibility of the plan of reorganization and our ability to continue operations upon our emergence from bankruptcy. Those projections were prepared solely for the purpose of the bankruptcy proceedings and have not been, and will not be, updated on an ongoing basis and should not be relied upon by investors. At the time they were prepared, the projections reflected numerous assumptions concerning our anticipated future performance and with respect to prevailing and anticipated market and economic conditions that were and remain beyond our control and that may not materialize. Projections are inherently subject to substantial and numerous uncertainties and to a wide variety of significant business, economic and competitive risks and the assumptions underlying the projections and/or valuation estimates may prove to be wrong in material respects. Actual results will likely vary significantly from those contemplated by the projections. As a result, investors should not rely on these projections.

Upon emergence from bankruptcy, our historical financial information may not be indicative of our future financial performance.

Our capital structure will be significantly altered under the Plan. Under fresh-start reporting rules that will apply to us upon the effective date of the Plan, our assets and liabilities will be adjusted to fair values and our accumulated deficit will be restated to zero. Further, as a result of the implementation of our plan of reorganization and the transactions contemplated thereby, our historical financial information may not be indicative of our future financial performance. In support of the Plan, our enterprise value was estimated and approved by the Bankruptcy Court to be in the range of $425.0 million and $475.0 million and upon emergence from the chapter 11 proceedings, we made an initial draw under the Exit Facility of $130.0 million. Accordingly, our financial condition and results of operations following our emergence from chapter 11 will not be comparable to the financial condition and results of operations reflected in our historical financial statements.

Upon our emergence from bankruptcy, the composition of our Board of Directors changed significantly.

Under the Plan, the composition of our Board of Directors (the Board) changed significantly from an eight member Board with three classes with terms of three years to, upon emergence, a seven member Board, structured into two classes with the first class serving until the 2020 Annual Meeting and the second class serving until the 2021 Annual Meeting. Commencing with the 2021 Annual Meeting, each nominee for director shall stand for election to a one-year term expiring at the next annual meeting of stockholders. None of our current directors served on our Board pre-emergence from bankruptcy. Our new directors have different backgrounds, experiences and perspectives from those individuals who previously served on the Board and, thus, may have different views on the issues

that will determine the future of the Company. As a result, the future strategy and plans of the Company may differ materially from those of the past.

There may be circumstances in which the interests of our significant stockholders could be in conflict with the interests of our other stockholders.

Funds advised by Luminus Management, LLC, Oaktree Capital Management, LP, and LSP Investment Advisors, LLC currently hold approximately 40.5%, 24.6% and 16.3%, respectively, of our post-reorganization common stock as of October 8, 2019. Circumstances may arise in which these stockholders may have an interest in pursuing or preventing acquisitions, divestitures or other transactions, including the issuance of additional shares or debt, that, in their judgment, could enhance their investment in us or another company in which they invest. Such transactions might adversely affect us or other holders of our common stock. In addition, our significant concentration of share ownership may adversely affect the trading price of our common shares because investors may perceive disadvantages in owning shares in companies with significant stockholders.

We depend on the continued presence of key personnel for critical management decisions.

Retaining and understanding historical knowledge from our key personnel is critical to allowing the new management team to more effectively progress our business plan. As part of the restructuring, there were a number of positions that were consolidated and/or replaced. While it is important to have the new team focused on the future, retaining and understanding the decisions that were made in the past allows for a more seamless transition into the future. Anytime personnel are replaced, there is a risk that there may be a loss of service, albeit temporary, that could result in an adverse effect on the business.

Our oil and natural gas activities are subject to various risks which are beyond our control.

Our operations are subject to many risks and hazards incident to exploring and drilling for, producing, transporting, marketing and selling oil and natural gas. Although we take precautionary measures, many of these risks and hazards are beyond our control and unavoidable under the circumstances. Many of these risks or hazards could materially and adversely affect our revenues and expenses, the ability of certain of our wells to produce oil and natural gas in commercial quantities, the rate of production and the economics of the development of, and our investment in, the prospects in which we have or will acquire an interest. Such risks and hazards include:

Some of these risks may be exacerbated by other risks that we face. For instance, certain of our wells produce high levels of H2S, a highly toxic, naturally-occurring gas frequently associated with oil and natural gas production. Safely handling H2S gas requires highly skilled operations and field personnel as well as specialized infrastructure, treating facilities, disposal facilities, and/or third party sour gas takeaway. If we are unable to attract and retain qualified and highly skilled personnel, whether as a result of uncertainty associated with our restructuring in bankruptcy or otherwise, our ability to effectively manage this and other risks may be adversely impacted. Additionally, if we are unable to obtain specialized infrastructure and/or successfully operate treating facilities or obtain regulatory approvals for new disposal facilities or secure adequate sour gas takeaway capacity from third parties, our ability to effectively manage the H2S levels we see in our gas production may be adversely impacted. As a result, our production, revenues, operating costs and liabilities and expenses may be materially and adversely affected and may differ materially from those anticipated by us.

Future sales of our common stock in the public market or the issuance of securities senior to our common stock, or the perception that these sales may occur, could adversely affect the trading price of our common stock and our ability to raise funds in stock offerings.

A large percentage of our shares of common stock are held by a relatively small number of investors. Further, we entered into a registration rights agreement with certain of those investors pursuant to which we have agreed to file a registration statement with the SEC to facilitate potential future sales of such shares by them. Sales by us or our stockholders of a substantial number of shares of our common stock in the public markets, or even the perception that these sales might occur (such as upon the filing of the aforementioned registration statement), could cause the market price of our common stock to decline or could impair our ability to raise capital through a future sale of, or pay for acquisitions using, our equity securities.

We are currently authorized to issue 100.0 million shares of common stock and 1.0 million shares of preferred stock, with such designations, rights, preferences, privileges and restrictions as determined by our board of directors. As of October 8, 2019, we had outstanding approximately 16.2 million shares of common stock and warrants to purchase an aggregate of 6.9 million shares of our common stock. The potential issuance of such additional shares of common stock may create downward pressure on the trading price of our common stock.

We may issue common stock or other equity securities senior to our common stock in the future for a number of reasons, including to finance acquisitions, to adjust our leverage ratio, and to satisfy our obligations upon the exercise of warrants, or for other reasons. We cannot predict the effect, if any, that future sales or issuances of shares of our common stock or other equity securities, or the availability of shares of common stock or such other equity securities for future sale or issuance, will have on the trading price of our common stock.

Transfers of our equity, or issuances of equity before or in connection with our chapter 11 proceedings, may impair our ability to utilize our federal income tax net operating loss carryforwards and other tax attributes during the current year and in future years.

Under federal income tax law, a corporation is generally permitted to offset net taxable income in a given year with net operating losses carried forward from prior years. We had net operating loss carryforwards (NOLs) of approximately $2.6 billion as of December 31, 2018; as previously reported, and subject to the following, we believe that only $975 million of the net operating loss carryforwards may be available for use, considering section 382 limitations currently asserted to be in effect, subject to our continued analysis.

Our ability to utilize our net operating loss carryforwards and other tax attributes to offset future taxable income and to reduce our federal income tax liability is subject to certain requirements and restrictions. If we experience an "ownership change" during or in connection with the restructuring process, as defined in section 382 of the Internal Revenue Code, then our ability to use our net operating loss carryforwards and other tax attributes may be substantially limited, which could have a negative impact on our financial position and results of operations. Generally, there is an "ownership change" if one or more stockholders owning 5% or more of a corporation's common stock have aggregate increases in their ownership of such stock of more than 50 percentage points over a prescribed testing period. Under section 382 and section 383 of the Internal Revenue Code, absent an applicable exception, if a corporation undergoes an "ownership change", the amount of its net operating losses and other tax attributes that may be utilized to offset future taxable income generally is subject to an annual limitation. Based on information collected to date, we believe we may have experienced an "ownership change" as of December 31, 2018, which would result in significant impairment in our ability to utilize our NOLs and tax attributes.

Whether or not the net operating loss carryforwards and other tax attributes are subject to limitation under section 382, our net operating losses and other tax attributes are expected to be further reduced by the amount of discharge of indebtedness arising in our chapter 11 case under section 108 of the Internal Revenue Code.

The Bankruptcy Court approved restrictions on certain transfers of our stock to limit the risk of an "ownership change" prior to our emergence from restructuring in our chapter 11 proceedings. We anticipate that the implementation of our plan of reorganization will result in an "ownership change." If so, our NOLs and other tax attributes may become further impaired.

The following table sets forth information regarding our acquisition of shares of common stock for the periods presented.

See Part I, Item 1, Note 2 to the Company's unaudited condensed consolidated financial statements entitled "Reorganization," which is incorporated in this item by reference.

The following documents are included as exhibits to this Quarterly Report on Form 10-Q. Those exhibits incorporated by reference are so indicated by the information supplied with respect thereto. Those exhibits which are not incorporated by reference are attached hereto.

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 hereunto duly authorized.


ý		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2019
OR
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to


Large accelerated filer o		Accelerated filer ý		Non-accelerated filer o		Smaller reporting company o Emerging growth company o

Title of each class		Trading Symbol		Name of each exchange on which registered

N/A		N/A		N/A



PART I—FINANCIAL INFORMATION
ITEM 1.	Condensed Consolidated Financial Statements (Unaudited) (Debtor-in-Possession)	4
	Condensed Consolidated Statements of Operations (Unaudited) for the Three Months and Nine Months Ended September 30, 2019 and 2018	4
	Condensed Consolidated Balance Sheets (Unaudited) as of September 30, 2019 and December 31, 2018	5
	Condensed Consolidated Statements of Stockholders' Equity (Unaudited) for the Three and Nine Months Ended September 30, 2019 and the Year Ended December 31, 2018	6
	Condensed Consolidated Statements of Cash Flows (Unaudited) for the Nine Months Ended September 30, 2019 and 2018	8
	Notes to Unaudited Condensed Consolidated Financial Statements	9
ITEM 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	42
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	60
ITEM 4.	Controls and Procedures	61
PART II—OTHER INFORMATION
ITEM 1.	Legal Proceedings	62
ITEM 1A.	Risk Factors	62
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	65
ITEM 3.	Defaults Upon Senior Securities	66
ITEM 4.	Mine Safety Disclosures	66
ITEM 5.	Other Information	66
ITEM 6.	Exhibits	66
Signatures		68

	Three Months Ended September 30, 2019

Accrued interest	$	20,274
Write-off debt discount/premium and debt issuance costs		(10,953	)
Reorganization professional fees and other		(11,079	)

Gain (loss) on reorganization items	$	(1,758	)


Delaware (State or other jurisdiction of incorporation or organization)		1311 (Primary Standard Industrial Classification Code Number)		20-0700684 (I.R.S. Employer Identification Number)

	September 30, 2019

6.75% senior notes due 2025	$	625,005

Liabilities subject to compromise	$	625,005

	September 30, 2019

Remaining period in 2019	$	380
2020		1,360
2021		876
2022		574
2023		585
Thereafter		345

Total operating lease payments		4,120

Less: discount to present value		345

Total operating lease liabilities		3,775

Less: current operating lease liabilities		1,337

Noncurrent operating lease liabilities	$	2,438

	December 31, 2018

2019	$	3,792
2020		2,350
2021		1,899
2022		968
2023		999
Thereafter		599

Total operating lease payments	$	10,607

	September 30, 2019		December 31, 2018

Debtor-in-possession credit facility⁽¹⁾	$	35,000	$	—
Senior revolving credit facility⁽¹⁾		223,234		—
6.75% senior notes due 2025⁽²⁾		—		613,105

	$	258,234	$	613,105

	September 30, 2019

	Level 1		Level 2		Level 3		Total
Assets
Receivables from derivative contracts	$	—	$	19,430	$	—	$	19,430



Liabilities
Liabilities from derivative contracts	$	—	$	8,454	$	—	$	8,454

	September 30, 2019				December 31, 2018

Debt	Principal Amount		Estimated Fair Value		Principal Amount		Estimated Fair Value
6.75% senior notes⁽¹⁾	$	625,005	$	60,963	$	625,005	$	458,210

		Asset derivative contracts					Liability derivative contracts

Derivatives not designated as hedging contracts under ASC 815	Balance sheet location	September 30, 2019		December 31, 2018		Balance sheet location	September 30, 2019			December 31, 2018
Commodity contracts	Current assets—receivables from derivative contracts	$	15,310	$	57,280	Current liabilities—liabilities from derivative contracts	$	(6,829	)	$	(3,768	)
Commodity contracts	Other noncurrent assets—receivables from derivative contracts		4,120		12,437	Other noncurrent liabilities—liabilities from derivative contracts		(1,625	)		(9,139	)

Total derivatives not designated as hedging contracts under ASC 815		$	19,430	$	69,717		$	(8,454	)	$	(12,907	)

	Derivative Assets						Derivative Liabilities

Offsetting of Derivative Assets and Liabilities	September 30, 2019			December 31, 2018			September 30, 2019			December 31, 2018
Gross Amounts Presented in the Consolidated Balance Sheet	$	19,430		$	69,717		$	(8,454	)	$	(12,907	)
Amounts Not Offset in the Consolidated Balance Sheet		(8,454	)		(10,263	)		8,454			10,263

Net Amount	$	10,976		$	59,454		$	—		$	(2,644	)


Liability for asset retirement obligations as of December 31, 2018	$	6,914
Liabilities settled and divested		(229	)
Additions		354
Accretion expense		307
Revisions in estimated cash flows		2,807

Liability for asset retirement obligations as of September 30, 2019	$	10,153

		Average Price Paid Per Share

July 2019	5,251	$	0.12	—	—
August 2019	2,836		0.13	—	—
September 2019	152,674		0.07	—	—


	HALCÓN RESOURCES CORPORATION
November 12, 2019	By:	/s/ RICHARD H. LITTLE
		Name:	Richard H. Little
		Title:	Chief Executive Officer
November 12, 2019	By:	/s/ RAGAN T. ALTIZER
		Name:	Ragan T. Altizer
		Title:	Executive Vice President, Chief Financial Officer and Treasurer


Remaining period in 2019	$	—
2020		3,000
2021		—
2022		—
2023		—
Thereafter		—

Total	$	3,000

	Nine Months Ended September 30,

	2019			2018
Cash flows provided by (used in) operating activities	$	(33,233	)	$	36,709
Cash flows provided by (used in) investing activities		(254,417	)		(778,127	)
Cash flows provided by (used in) financing activities		257,793			317,484

Net increase (decrease) in cash and cash equivalents	$	(29,857	)	$	(423,934	)


	2.1		Order of the Bankruptcy Court, dated September 24, 2019, confirming the Debtors' Joint Prepackaged Plan of Reorganization, together with such Joint Prepackaged Plan of Reorganization (Incorporated by reference to Exhibit 2.1 of our Current Report on Form 8-K filed September 25, 2019).
	2.2		Disclosure Statement for Joint Prepackaged Chapter 11 Plan (Incorporated by reference to Exhibit 2.2 of our Current Report on Form 8-K filed August 7, 2019).
	3.1		Amended and Restated Certificate of Incorporation of Halcón Resources Corporation dated October 8, 2019 (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed October 8, 2019).
	3.2		Sixth Amended and Restated Bylaws of Halcón Resources Corporation (Incorporated by reference to Exhibit 3.2 of our Current Report on Form 8-K filed October 8, 2019).
	3.2.1		Amendment No. 1 to the Fifth Amended and Restated Bylaws of Halcón Resources Corporation (Incorporated by reference to Exhibit 3.2 of our Current Report on Form 8-K filed September 9, 2016).
	10.1		Eighth Amendment to Amended and Restated Senior Secured Revolving Credit Agreement, dated as of May 9, 2019, by and among Halcón Resources Corporation, JPMorgan Chase Bank, N.A., as administrative agent, and certain other financial institutions party thereto, as lenders. (Incorporated by reference to Exhibit 10.1.7 of our Quarterly Report on Form 10-Q filed May 9, 2019).
	10.2		Offer letter with Richard H. Little dated June 10, 2019 (Incorporated by reference to Exhibit 10.2 of our Quarterly Report on Form 10-Q filed August 9, 2019).
	10.3		Restructuring Support Agreement with certain noteholders dated August 2, 2019 (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed August 5, 2019).
	10.4		Backstop Commitment Agreement with certain noteholders dated August 2, 2019 (Incorporated by reference to Exhibit 10.2 of our Current Report on Form 8-K filed August 5, 2019).


10.5		Exit Commitment Letter with BMO Harris Bank, N.A., and BMO Capital Markets Corp. dated August 2, 2019 (Incorporated by reference to Exhibit 10.3 of our Current Report on Form 8-K filed August 5, 2019).
10.6		Waiver to Amended and Restated Senior Secured Credit Agreement dated as of July 31, 2019 (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed August 1, 2019).
10.7		Senior Secured Revolving Credit Agreement dated as of October 8, 2019, by and among Halcón Resources Corporation, as borrower, Bank of Montreal, as administrative agent, and the lenders party thereto (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed October 8, 2019).
10.8		Warrant Agreement, between Halcón Resources Corporation, as Issuer, and Broadridge Corporate Issuer Solutions, Inc., as Warrant Agent, dated October 8, 2019 (Incorporated by reference to Exhibit 10.2 of our Current Report on Form 8-K filed October 8, 2019).
10.9		Registration Rights Agreement, between Halcón Resources Corporation and the rights holders thereto, dated October 8, 2019 (Incorporated by reference to Exhibit 10.3 of our Current Report on Form 8-K filed October 8, 2019).
10.10		Joint Secured Debtor-In-Possession Credit Agreement (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed August 9, 2019).
10.11		Amended and Restated Employment Agreement, dated September 3, 2019, by and between Halcón Resources Corporation and Jon Wright (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed September 27, 2019).
10.12		Amended and Restated Employment Agreement, dated September 3, 2019, by and between Halcón Resources Corporation and David S. Elkouri (Incorporated by reference to Exhibit 10.2 of our Current Report on Form 8-K filed September 27, 2019).
10.13	*	Offer letter with Ragan Altizer dated July 22, 2019.
10.14	*	Offer letter with Daniel Rohling dated July 22, 2019.
10.15	*	Retention Bonus Agreement with Jon Wright dated July 12, 2019.
10.16	*	Retention Bonus Agreement with David Elkouri dated July 12, 2019.
31.1	*	Sarbanes-Oxley Section 302 certification of Principal Executive Officer
31.2	*	Sarbanes-Oxley Section 302 certification of Principal Financial Officer
32	*	Sarbanes-Oxley Section 906 certification of Principal Executive Officer and Principal Financial Officer
101.INS	*	XBRL Instance Document
101.SCH	*	XBRL Taxonomy Extension Schema Document
101.CAL	*	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	*	XBRL Taxonomy Extension Definition Document
101.LAB	*	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	*	XBRL Taxonomy Extension Presentation Linkbase Document