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

1000 Louisiana Street, Suite 6700, Houston, TX 77002
(Address of principal executive offices)

(Former name, former address and former fiscal year, if changed since last report)

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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post 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, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

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

At November 2, 2015, 605,177,240 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, concerning, among other things, planned capital expenditures, potential increases in oil and natural gas production, the number and location of wells to be drilled in the future, future cash flows and borrowings, pursuit of potential acquisition or divestiture opportunities, our financial position, business strategy and other plans and objectives for future operations, are forward-looking statements. These forward-looking statements are identified by their use of terms and phrases such as "may," "expect," "estimate," "project," "plan," "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, 2014 and 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.

HALCÓN RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(In thousands, except per share amounts)

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

	2015			2014			2015			2014
Operating revenues:
Oil, natural gas and natural gas liquids sales:
Oil	$	121,845		$	287,863		$	404,368		$	848,104
Natural gas		5,058			8,248			17,595			27,965
Natural gas liquids		2,615			10,273			10,572			28,396

Total oil, natural gas and natural gas liquids sales		129,518			306,384			432,535			904,465
Other		421			125			1,622			4,337

Total operating revenues		129,939			306,509			434,157			908,802

Operating expenses:
Production:
Lease operating		22,248			28,094			81,266			95,700
Workover and other		4,769			5,773			11,614			12,550
Taxes other than income		12,102			28,532			37,246			83,002
Gathering and other		9,091			7,460			30,583			18,119
Restructuring		434			—			2,664			987
General and administrative		21,027			29,569			68,098			90,110
Depletion, depreciation and accretion		77,071			135,578			297,409			388,956
Full cost ceiling impairment		511,882			—			2,014,518			61,165
Other operating property and equipment impairment		—			—			—			3,789

Total operating expenses		658,624			235,006			2,543,398			754,378

Income (loss) from operations		(528,685	)		71,503			(2,109,241	)		154,424
Other income (expenses):
Net gain (loss) on derivative contracts		204,621			163,287			216,805			8,589
Interest expense and other, net		(57,977	)		(38,450	)		(180,206	)		(107,114	)
Gain (loss) on extinguishment of debt		535,141			—			557,907			—
Gain (loss) on extinguishment of Convertible Note and modification of February 2012 Warrants		—			—			(8,219	)		—

Total other income (expenses)		681,785			124,837			586,287			(98,525	)

Income (loss) before income taxes		153,100			196,340			(1,522,954	)		55,899
Income tax benefit (provision)		(6,025	)		1,295			(6,224	)		1,295

Net income (loss)		147,075			197,635			(1,529,178	)		57,194
Series A preferred dividends		(4,196	)		(4,959	)		(13,999	)		(14,878	)
Preferred dividends and accretion on redeemable noncontrolling interest		(19,351	)		(5,823	)		(39,069	)		(6,719	)

Net income (loss) available to common stockholders	$	123,528		$	186,853		$	(1,582,246	)	$	35,597



Net income (loss) per share of common stock:
Basic	$	0.21		$	0.45		$	(3.06	)	$	0.09



Diluted	$	0.18		$	0.36		$	(3.06	)	$	0.08



Weighted average common shares outstanding:
Basic		586,053			416,470			517,624			415,264



Diluted		754,782			548,246			517,624			423,033

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

HALCÓN RESOURCES CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

(In thousands, except share and per share amounts)

	September 30, 2015			December 31, 2014

Current assets:
Cash	$	6,254		$	43,713
Accounts receivable		191,247			276,559
Receivables from derivative contracts		327,535			352,530
Restricted cash		16,541			16,131
Inventory		4,045			4,693
Prepaids and other		6,861			9,079

Total current assets		552,483			702,705

Oil and natural gas properties (full cost method):
Evaluated		6,783,169			6,390,820
Unevaluated		1,817,237			1,829,786

Gross oil and natural gas properties		8,600,406			8,220,606
Less—accumulated depletion		(5,257,516	)		(2,953,038	)

Net oil and natural gas properties		3,342,890			5,267,568

Other operating property and equipment:
Gas gathering and other operating assets		130,080			126,804
Less—accumulated depreciation		(20,498	)		(14,798	)

Net other operating property and equipment		109,582			112,006

Other noncurrent assets:
Receivables from derivative contracts		73,583			151,324
Debt issuance costs, net		42,598			55,904
Deferred income taxes		127,623			136,826
Equity in oil and natural gas partnership		4,082			4,309
Funds in escrow and other		1,921			3,833

Total assets	$	4,254,762		$	6,434,475



Current liabilities:
Accounts payable and accrued liabilities	$	336,595		$	607,750
Asset retirement obligations		144			106
Current portion of deferred income taxes		127,623			136,826

Total current liabilities		464,362			744,682

Long-term debt		3,111,229			3,746,736
Other noncurrent liabilities:
Liabilities from derivative contracts		623			9,387
Asset retirement obligations		42,069			38,371
Other		7,306			5,964
Commitments and contingencies (Note 8)
Mezzanine equity:
Redeemable noncontrolling interest		156,235			117,166
Stockholders' equity:
Preferred stock: 1,000,000 shares of $0.0001 par value authorized; 244,934 and 345,000 shares of 5.75% Cumulative Perpetual Convertible Series A, issued and outstanding at September 30, 2015 and December 31, 2014, respectively		—			—
Common stock: 1,340,000,000 shares of $0.0001 par value authorized; 605,328,701 and 427,808,306 shares issued and outstanding at September 30, 2015 and December 31, 2014, respectively		61			42
Additional paid-in capital		3,278,858			2,995,402
Accumulated deficit		(2,805,981	)		(1,223,275	)

Total stockholders' equity		472,938			1,772,169

Total liabilities and stockholders' equity	$	4,254,762		$	6,434,475

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

HALCÓN RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Unaudited)

(In thousands)

	Preferred Stock					Common Stock

	Preferred Stock					Common Stock					Additional Paid-In Capital			Accumulated Deficit			Stockholders' Equity
	Shares			Amount		Shares			Amount		Additional Paid-In Capital			Accumulated Deficit			Stockholders' Equity
Balances at December 31, 2013		345		$	—		415,730		$	41	$	2,953,786		$	(1,506,217	)	$	1,447,610
Net income (loss)		—			—		—			—		—			315,956			315,956
Dividends on Series A preferred stock		—			—		3,262			—		14,878			(19,838	)		(4,960	)
Preferred dividends on redeemable noncontrolling interest		—			—		—			—		—			(6,543	)		(6,543	)
Accretion of redeemable noncontrolling interest		—			—		—			—		—			(6,633	)		(6,633	)
Offering costs		—			—		—			—		39			—			39
Long-term incentive plan grants		—			—		9,388			1		(1	)		—			—
Long-term incentive plan forfeitures		—			—		(455	)		—		—			—			—
Reduction in shares to cover individuals' tax withholding		—			—		(117	)		—		(453	)		—			(453	)
Share-based compensation		—			—		—			—		27,153			—			27,153

Balances at December 31, 2014		345			—		427,808			42		2,995,402			(1,223,275	)		1,772,169
Net income (loss)		—			—		—			—		—			(1,529,178	)		(1,529,178	)
Dividends on Series A preferred stock		—			—		6,769			1		9,802			(14,459	)		(4,656	)
Conversion of Series A preferred stock		(100	)		—		16,255			2		(2	)		—			—
Preferred dividends on redeemable noncontrolling interest		—			—		—			—		—			(9,340	)		(9,340	)
Accretion of redeemable noncontrolling interest		—			—		—			—		—			(29,084	)		(29,084	)
Change in fair value of redeemable noncontrolling interest		—			—		—			—		—			(645	)		(645	)
Common stock issuance		—			—		9,436			1		15,353			—			15,354
Common stock issuance on conversion of senior notes		—			—		144,775			15		231,368			—			231,383
Offering costs		—			—		—			—		(1,795	)		—			(1,795	)
Modification of February 2012 Warrants		—			—		—			—		14,129			—			14,129
Long-term incentive plan grants		—			—		2,387			—		—			—			—
Long-term incentive plan forfeitures		—			—		(1,696	)		—		—			—			—
Reduction in shares to cover individuals' tax withholding		—			—		(405	)		—		(777	)		—			(777	)
Share-based compensation		—			—		—			—		15,378			—			15,378

Balances at September 30, 2015		245		$	—		605,329		$	61	$	3,278,858		$	(2,805,981	)	$	472,938

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

HALCÓN RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(In thousands)

	Nine Months Ended September 30,

	2015			2014
Cash flows from operating activities:
Net income (loss)	$	(1,529,178	)	$	57,194
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depletion, depreciation and accretion		297,409			388,956
Full cost ceiling impairment		2,014,518			61,165
Other operating property and equipment impairment		—			3,789
Share-based compensation, net		11,245			13,837
Unrealized loss (gain) on derivative contracts		93,972			(38,660	)
Amortization and write-off of deferred loan costs		6,002			3,198
Non-cash interest and amortization of discount and premium		2,029			1,976
Loss (gain) on extinguishment of debt		(557,907	)		—
Loss (gain) on extinguishment of Convertible Note and modification of February 2012 Warrants		8,219			—
Accrued settlements on derivative contracts		(37,803	)		—
Other income (expense)		5,805			(594	)
Change in assets and liabilities, net of acquisitions:
Accounts receivable		75,331			31,020
Inventory		(2	)		(962	)
Prepaids and other		2,218			1,742
Accounts payable and accrued liabilities		(59,664	)		59,229

Net cash provided by (used in) operating activities		332,194			581,890

Cash flows from investing activities:
Oil and natural gas capital expenditures		(531,741	)		(1,178,649	)
Proceeds received from sale of oil and natural gas assets		1,111			479,974
Advance on carried interest		—			(189,442	)
Other operating property and equipment capital expenditures		(9,913	)		(40,356	)
Funds held in escrow and other		1,877			1,221

Net cash provided by (used in) investing activities		(538,666	)		(927,252	)

Cash flows from financing activities:
Proceeds from borrowings		1,579,000			1,744,000
Repayments of borrowings		(1,392,000	)		(1,399,000	)
Debt issuance costs		(25,703	)		(757	)
Series A preferred dividends		(4,656	)		—
Common stock issued		15,354			—
HK TMS, LLC preferred stock issued		—			110,051
HK TMS, LLC tranche rights		—			4,516
Preferred dividends on redeemable noncontrolling interest		—			(3,518	)
Restricted cash		(410	)		(15,984	)
Offering costs and other		(2,572	)		(2,092	)

Net cash provided by (used in) financing activities		169,013			437,216

Net increase (decrease) in cash		(37,459	)		91,854
Cash at beginning of period		43,713			2,834

Cash at end of period	$	6,254		$	94,688



Disclosure of non-cash investing and financing activities:
Accrued capitalized interest	$	(442	)	$	(5,340	)
Asset retirement obligations		2,405			(3,396	)
Series A preferred dividends paid in common stock		9,803			14,878
Preferred dividends on redeemable noncontrolling interest paid-in-kind		9,340			—
Accretion of redeemable noncontrolling interest		29,084			3,201
Change in fair value of redeemable noncontrolling interest		645			—
Common stock issued on conversion of senior notes		231,383			—
Third Lien Notes issued on conversion of senior notes		1,017,994			—

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

HALCÓN RESOURCES CORPORATION

NOTES TO 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 assets in the United States. The unaudited condensed consolidated financial statements include the accounts of all majority-owned, controlled subsidiaries and an equity method investment. The Company operates in one segment which focuses on oil and natural gas acquisition, production, exploration and development. The Company's oil and natural gas properties are managed as a whole rather than through discrete operating areas. Operational information is tracked by operating area; however, financial performance is assessed as a whole. 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 2014 Annual Report on Form 10-K, as filed with the United States Securities and Exchange Commission (SEC) on February 26, 2015. Please refer to the notes in the 2014 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 management of the Company, are significant include oil and natural gas revenue, 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 that are believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be perceived 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.

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. There were no material allowances for doubtful accounts as of September 30, 2015 or December 31, 2014.

Gas gathering systems and equipment are recorded at cost. Depreciation is calculated using the straight-line method over a 30-year or 10-year estimated useful life applicable to gas gathering systems and a compressed natural gas facility, respectively. 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 capitalized $87.4 million and $83.1 million as of September 30, 2015 and December 31, 2014, respectively, related to the construction of its gas gathering systems, after any amounts impaired.

Other operating assets are recorded at cost. Depreciation is calculated using the straight-line method over the following estimated useful lives: automobiles and computers, three years; computer software, fixtures, furniture and equipment, five years or the lesser of the lease term; trailers, seven years; heavy equipment, ten years; buildings, twenty 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 of an asset are capitalized and depreciated over the estimated remaining useful life of the asset.

The Company reviews its gas gathering systems and equipment and other operating assets for impairment in accordance with ASC 360, Property, Plant, and Equipment (ASC 360). ASC 360 requires the Company to evaluate gas gathering systems and equipment and other operating 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 an asset's undiscounted cash flows, then the Company recognizes an impairment loss for the difference between the carrying amount and the current fair value. The Company also evaluates the remaining useful lives of its gas gathering systems and other operating assets at each reporting period to determine whether events and circumstances warrant a revision to the remaining depreciation periods.

Operating results for the nine months ended September 30, 2014 reflect the impact of approximately $3.8 million in charges related to the disposition of midstream infrastructure assets associated with certain non-core property divestitures. The impairment of midstream assets was recorded in "Other operating property and equipment impairment" in the Company's unaudited condensed consolidated statements of operations and in "Gas gathering and other operating assets" in the Company's unaudited condensed consolidated balance sheets.

In accordance with ASC 820, Fair Value Measurements and Disclosures (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 estimate of the fair value of the Company's gas gathering systems was based on an income approach that estimated future cash flows associated with those assets, which

resulted in negative net cash flows due to insufficient throughput of natural gas volumes and certain fixed costs necessary to operate and maintain the assets. This estimation includes the use of unobservable inputs, such as estimated future production, gathering and compression revenues and operating expenses. The use of these unobservable inputs results in the fair value estimate of the Company's gas gathering systems being classified as Level 3.

In August 2015, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2015-15, Presentation and Subsequent Measurement of Debt Issuance Costs with Line-of-Credit Arrangements (ASU 2015-15). The previous guidance in ASU 2015-03, as defined below, did not address the presentation or subsequent measurement of debt issuance costs related to line-of-credit arrangements. Given the absence of authoritative guidance within ASU 2015-03, the SEC staff would not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. ASU 2015-15 is effective for public entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted and entities shall apply the guidance retrospectively to all prior year periods presented. The Company is in the process of assessing the effects of the application of the new guidance.

In July 2015, the FASB issued ASU No. 2015-11, Simplifying the Measurement of Inventory (ASU 2015-11). ASU 2015-11 states that an entity should measure inventory at the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. For public entities, ASU 2015-11 is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. The amendments in this update should be applied prospectively and early application is permitted. The Company does not expect the adoption of ASU 2015-11 to have a material impact to its financial statements or disclosures.

In April 2015, the FASB issued ASU No. 2015-05, Intangibles—Goodwill and Other—Internal-Use Software (ASU 2015-05). ASU 2015-05 provides guidance to customers about whether a cloud computing arrangement includes a software license. If a cloud computing arrangement includes a software license, then the customer should account for the software license element of the arrangement consistent with the acquisition of other software licenses. If a cloud computing arrangement does not include a software license, the customer should account for the arrangement as a service contract. For public business entities, the guidance is effective for annual periods, including interim periods within those annual periods, beginning after December 15, 2015. An entity can elect to adopt the guidance either (1) prospectively to all arrangements entered into or materially modified after the effective date or (2) retrospectively. Early adoption is permitted. The Company does not expect the adoption of ASU 2015-05 to have a material impact to its financial statements or disclosures.

In April 2015, the FASB issued ASU No. 2015-03, Simplifying the Presentation of Debt Issuance Costs (ASU 2015-03). To simplify presentation of debt issuance costs, ASU 2015-03 requires that debt issuance costs be presented in the balance sheet as a direct deduction from the carrying amount of the debt liability, consistent with debt discounts. ASU 2015-03 is effective for public entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is

permitted and entities shall apply the guidance retrospectively to all prior year periods presented. The Company is in the process of assessing the effects of the application of the new guidance.

In February 2015, the FASB issued ASU No. 2015-02, Amendments to the Consolidation Analysis (ASU 2015-02). The amendments in ASU 2015-02 eliminate the previous presumption that a general partner controls a limited partner. ASU 2015-02 may impact the Company's accounting for its general partner interest in SBE Partners LP (SBE Partners), which is currently accounted for as an equity method investment. ASU 2015-02 is effective for public entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted. Entities may apply the guidance using a modified retrospective approach by recording a cumulative-effect adjustment to equity as of the beginning of the first fiscal year adopted or it may apply the amendment retrospectively. The Company is currently assessing the impact of ASU 2015-02 on its accounting for its general partner interest in SBE Partners.

In August 2014, the FASB issued ASU No. 2014-15, Presentation of Financial Statements—Going Concern (ASU 2014-15). ASU 2014-15 is effective for annual reporting periods (including interim periods within those periods) ending after December 15, 2016. Early application is permitted with companies applying the guidance prospectively. The amendments in ASU 2014-15 create a new ASC Sub-topic 205-40, Presentation of Financial Statements—Going Concern and require management to assess for each annual and interim reporting period if conditions exist that raise substantial doubt about an entity's ability to continue as a going concern. The rule requires various disclosures depending on the facts and circumstances surrounding an entity's ability to continue as a going concern. The Company is in the process of assessing the effects of the application of the new guidance.

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (ASU 2014-09). ASU 2014-09 states that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard provides five steps an entity should apply in determining its revenue recognition. ASU 2014-09 must be applied retrospectively and is effective for annual reporting periods, and interim periods within that reporting period, beginning after December 15, 2016, or after December 2017, if companies choose to elect the deferred adoption date recently approved by the FASB. Early adoption is not permitted. The Company is in the process of assessing the effects of the application of the new guidance.

On May 9, 2014, the Company completed the divestiture of certain non-core assets in East Texas (the East Texas Assets) to a privately-owned company for a total purchase price of $424.5 million after closing adjustments for operating expenses, capital expenditures and revenues between the effective date and the closing date, title and environmental defects, and other purchase price adjustments customary in oil and gas purchase and sale agreements. The effective date of the transaction was April 1, 2014. Proceeds from the sale were recorded as a reduction to the carrying value of the Company's full cost pool with no gain or loss recorded.

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.

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.

Investments in unevaluated oil and natural gas properties and exploration and development projects for which depletion expense is not currently recognized, and for which exploration or development activities are in progress, qualify for interest capitalization. The capitalized interest is determined by multiplying the Company's weighted-average borrowing cost on debt by the average amount of qualifying costs incurred that are excluded from the full cost pool; however, the amount of capitalized interest cannot exceed the amount of gross interest expense incurred in any given period. The capitalized interest amounts are recorded as additions to unevaluated oil and natural gas properties on the unaudited condensed consolidated balance sheets. As the costs excluded are transferred to the full cost pool, the associated capitalized interest is also transferred to the full cost pool. For the nine months ended September 30, 2015 and 2014, the Company capitalized interest costs of $80.0 million and $128.9 million, respectively.

At September 30, 2015, 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, 2015 of the West Texas Intermediate (WTI) crude oil spot price of $59.21 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, 2015 of the Henry Hub natural gas price of $3.06 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, 2015 exceeded the ceiling amount by $511.9 million ($322.3 million after taxes before valuation allowance) which resulted in a ceiling test impairment of that amount for the quarter. At June 30, 2015 and March 31, 2015, the Company recorded full cost ceiling impairments before income taxes of $948.6 million ($597.3 million after taxes before valuation allowance) and $554.0 million ($348.8 million after taxes before valuation allowance), respectively. The ceiling test impairments were driven by decreases in the first-day-of-the-month average prices for crude oil used in the ceiling test calculations since December 31, 2014, when the first-day-of-the-month average price for crude oil was $94.99 per barrel.

At September 30, 2014, 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, 2014 of the WTI crude oil spot price of $99.08 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, 2014 of the Henry Hub natural gas price of $4.24 per MMBtu, adjusted by lease or field for energy content, transportation fees, and regional price differentials. The Company's net book value of oil and natural gas properties at September 30, 2014 did not exceed the ceiling amount. At March 31, 2014, the Company recorded a full cost ceiling test impairment before income taxes of $61.2 million ($39.0 million after taxes).

The Company recorded the full cost ceiling test impairments in "Full cost ceiling impairment" in the Company's unaudited condensed consolidated statements of operations and in "Accumulated depletion" in the Company's unaudited condensed consolidated balance sheets. Changes in commodity prices, production rates, levels of reserves, future development costs, transfers of unevaluated properties, and other factors will determine the Company's ceiling test calculations and impairment analyses in future periods.

Long-term debt as of September 30, 2015 and December 31, 2014 consisted of the following:

$8.5 million and $24.6 million at September 30, 2015 and December 31, 2014, respectively. See "8.875% Senior Notes" below for more details.

(4): Amounts are net of a $2.7 million and a $7.9 million unamortized discount at September 30, 2015 and December 31, 2014, respectively, related to the issuance of the original 2020 Notes. The unamortized premium related to the additional 2020 Notes was approximately $3.7 million and $9.7 million at September 30, 2015 and December 31, 2014, respectively. See "9.75% Senior Notes" below for more details.
(5): On May 6, 2015, an amendment to the 8.0% convertible note became effective and was accounted for as a debt extinguishment. Accordingly, the Company expensed the unamortized discount related to the pre-amendment 8.0% convertible note of $18.6 million and recorded a discount of $25.9 million to be amortized over the remaining life of the post-amendment 8.0% convertible note. The remaining unamortized discounts at September 30, 2015 and December 31, 2014 were $24.2 million and $21.8 million, respectively. See "8.0% Convertible Note" below for more details.

On February 8, 2012, the Company entered into a senior secured revolving credit agreement (the Senior Credit Agreement) with JPMorgan Chase Bank, N.A., as administrative agent, and the other lenders party thereto. The Senior Credit Agreement currently provides for a $1.5 billion facility with a current borrowing base of $850.0 million. On October 29, 2015, the Company's borrowing base under its Senior Credit Agreement was reaffirmed at $850.0 million with the next redetermination scheduled for spring of 2016. Amounts borrowed under the Senior Credit Agreement will mature on August 1, 2019. The borrowing base will be 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 takes into account 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 borrowing base is subject to a reduction, in most cases, equal to the product of 0.25 multiplied by the stated principal amount (without regard to any initial issue discount) of any future notes or other long-term debt securities that the Company may issue. Funds advanced under the Senior Credit Agreement may be paid down and re-borrowed during the term of the facility. Amounts outstanding under the Senior Credit Agreement bear interest at specified margins over the base rate of 0.75% to 1.75% for ABR-based loans or at specified margins over LIBOR of 1.75% to 2.75% for Eurodollar-based loans. These margins fluctuate based on the Company's utilization of the facility. At September 30, 2015, the weighted average interest rate on our variable rate debt was 4.0% per year. Advances under the Senior Credit Agreement are secured by liens on substantially all of the Company's and its restricted subsidiaries' properties and assets. The Senior Credit Agreement contains customary representations, warranties and covenants including, among others, restrictions on the payment of dividends on the Company's capital stock and financial covenants, including minimum working capital levels (the ratio of current assets plus the unused commitment under the Senior Credit Agreement to current liabilities) of not less than 1.0 to 1.0 and a ratio of total secured debt (excluding the Third Lien Notes pursuant to the Eleventh Amendment, as defined and discussed below) to EBITDA of no greater than 2.75 to 1.0.

On September 10, 2015, in conjunction with the issuance of the Third Lien Notes (defined below), the Company entered into the Eleventh Amendment to its Senior Credit Agreement (the Eleventh Amendment) which, among other things, permitted the Company to incur the debt under the Third Lien Notes and to grant the liens in connection therewith; excluded the Third Lien Notes from the calculation of the total secured debt to EBITDA ratio; and reduced the borrowing base to $850.0 million. On May 1, 2015, the Company entered into the Tenth Amendment to the Senior Credit Agreement (the Tenth Amendment) which, among other things, replaced the interest coverage test with a covenant that requires the ratio of total secured debt to EBITDA of no greater than 2.75 to 1.0 and reduced the borrowing base. Prior to the Tenth Amendment, under the Ninth Amendment executed on February 25, 2015, the Senior Credit Agreement had a required minimum coverage of interest expenses of not less than 2.0 to 1.0 through March 31, 2016 and not less than 2.5 to 1.0 for subsequent periods.

At September 30, 2015, under the effective borrowing base of $850.0 million, the Company had $44.0 million of indebtedness outstanding, $1.6 million of letters of credit outstanding and approximately $804.4 million of borrowing capacity available under the Company's Senior Credit Agreement.

At September 30, 2015, the Company was in compliance with the financial covenants under the Senior Credit Agreement.

On May 1, 2015, the Company issued $700 million aggregate principal amount of its 8.625% senior secured notes due 2020 (the Second Lien Notes) in a private offering. The Second Lien Notes were issued at par. The net proceeds from the sale of the Second Lien Notes were approximately $686.2 million (after deducting offering fees and expenses). The Company used the net proceeds from the offering to repay the majority of the then outstanding borrowings under its Senior Credit Agreement.

The Second Lien Notes bear interest at a rate of 8.625% per annum, payable semi-annually on February 1 and August 1 of each year, beginning on August 1, 2015. The Second Lien Notes will mature on February 1, 2020. The Second Lien Notes are secured by second-priority liens on substantially all of the Company's and its guarantors' assets to the extent such assets secure the Company's Senior Credit Agreement (the Collateral). Pursuant to the terms of the Intercreditor Agreement, dated May 1, 2015 (the Intercreditor Agreement), the security interest in those assets that secure the Second Lien Notes and the guarantees are contractually subordinated to liens that secure the Company's Senior Credit Agreement and certain other permitted indebtedness. Consequently, the Second Lien Notes and the guarantees are effectively subordinated to the Senior Credit Agreement and such other indebtedness to the extent of the value of such assets. The Collateral does not include any of the assets of HK TMS, LLC, a wholly owned subsidiary of the Company, or any of the Company's future unrestricted subsidiaries.

At any time prior to February 1, 2017, the Company may redeem the Second Lien Notes, in whole or in part, at a redemption price equal to 100% of their principal amount plus a make-whole premium, together with accrued and unpaid interest, if any, to the redemption date. The Second Lien Notes will

be redeemable, in whole or in part, on or after February 1, 2017 at redemption prices equal to the principal amount multiplied by the percentage set forth below, plus accrued and unpaid interest:

Additionally, the Company may redeem up to 35% of the Second Lien Notes on or prior to February 1, 2017 for a redemption price of 108.625% of the principal amount thereof, plus accrued and unpaid interest, utilizing net cash proceeds from certain equity offerings. In addition, upon a change of control of the Company, holders of the Second Lien Notes will have the right to require the Company to repurchase all or any part of their notes for cash at a price equal to 101% of the aggregate principal amount of the Second Lien Notes repurchased, plus any accrued and unpaid interest.

On September 10, 2015, the Company issued approximately $1.02 billion aggregate principal amount of its new 13.0% third lien senior secured notes due 2022 (the Third Lien Notes) in exchange for approximately $497.2 million principal amount of its 9.75% senior note due 2020, $774.7 million principal amount of its 8.875% senior notes due 2021 and $294.4 million principal amount of its 9.25% senior notes due 2022 in privately negotiated transactions with certain holders of its outstanding senior unsecured notes. At closing the Company paid all accrued and unpaid interest since the respective interest payment dates of the notes surrendered in the exchange. The Company recorded the issuance of the Third Lien Notes at par value and also recognized a $535.1 million net gain on the extinguishment of debt, as a $548.2 million gain on the exchanges was partially offset by the writedown of $13.1 million associated with related issuance costs and discounts and premiums for the respective notes. The net gain is recorded in "Gain (loss) on extinguishment of debt" in the unaudited condensed consolidated statements of operations.

The Third Lien Notes bear interest at a rate of 13.0% per annum, payable semi-annually on February 15 and August 15, commencing on February 15, 2016. The Third Lien Notes mature on February 15, 2022. The Third Lien Notes are secured by third-priority liens on the same collateral securing the Company's Senior Credit Agreement and Second Lien Notes. The Third Lien Notes are governed by an Indenture dated September 10, 2015, which contains affirmative and negative covenants substantially similar to those governing the Company's outstanding Second Lien Notes. Pursuant to the terms of the Intercreditor Agreement, the security interest in those assets that secure the Third Lien Notes and the guarantees are contractually subordinated to liens that secure the Company's Senior Credit Agreement, the Second Lien Notes and certain other permitted indebtedness. Consequently, the Third Lien Notes and the guarantees are effectively subordinated to the Senior Credit Agreement, the Second Lien Notes and such other indebtedness to the extent of the value of such assets. The Third Lien Notes are fully and unconditionally guaranteed on a senior basis by the Guarantors and by certain future subsidiaries of the Company.

At any time prior to August 15, 2018, the Company may redeem the Third Lien Notes, in whole or in part, at a redemption price equal to 100% of their principal amount plus a make-whole premium, together with accrued and unpaid interest, if any, to the redemption date. The Third Lien Notes will be redeemable, in whole or in part, on or after August 15, 2018, at redemption prices equal to the principal amount multiplied by the percentage set forth below, plus accrued and unpaid interest:

Additionally, the Company may redeem up to 35% of the Third Lien Notes prior to August 15, 2018 for a redemption price of 113% of the principal amount thereof, plus accrued and unpaid interest, utilizing net cash proceeds from certain equity offerings. In addition, upon a change of control of the Company, holders of the Third Lien Notes will have the right to require the Company to repurchase all or any part of their notes for cash at a price equal to 101% of the aggregate principal amount of the Third Lien Notes repurchased, plus any accrued and unpaid interest.

The Company issued the Third Lien Notes in reliance on the exemption from registration provided by Section 4(a)(2) of the Securities Act of 1933, as amended. The Company relied on this exemption from registration based in part on representations made by the holders of the senior unsecured notes.

On August 13, 2013, the Company issued at par $400.0 million aggregate principal amount of 9.25% senior notes due 2022 (the 2022 Notes). The net proceeds from the offering of approximately $392.1 million (after deducting commissions and offering expenses) were used to repay a portion of the then outstanding borrowings under the Company's Senior Credit Agreement.

The 2022 Notes bear interest at a rate of 9.25% per annum, payable semi-annually on February 15 and August 15 of each year, beginning on February 15, 2014. The 2022 Notes will mature on February 15, 2022. The 2022 Notes are senior unsecured obligations of the Company and are effectively subordinate to its secured debt, including secured debt under the Senior Credit Agreement, the Second Lien Notes and the Third Lien Notes and rank equally with all of its current and future senior indebtedness. The 2022 Notes are jointly and severally, fully and unconditionally guaranteed on a senior unsecured basis by the Company's existing 100% owned subsidiaries, except for the subsidiary, HK TMS, LLC. Halcón, the issuer of the 2022 Notes, has no material independent assets or operations apart from the assets and operations of its subsidiaries.

During the second quarter of 2015, the Company entered into several exchange agreements with holders of the Company's 2022 Notes in which they agreed to exchange an aggregate $7.4 million principal amount of their senior notes for approximately 4.3 million shares of the Company's common stock, thereby reducing the aggregate principal amount of the 2022 Notes. The exchanges closed on various dates from April 30, 2015 through May 15, 2015, at which time the Company also paid all accrued and unpaid interest since the prior interest payment date for the 2022 Notes. See "Senior Notes Exchanged for Common Stock" below for more details.

On September 10, 2015, the Company closed several separate, privately negotiated exchange agreements with holders of the Company's 2022 Notes in which they agreed to exchange an aggregate $294.4 million principal amount of their senior unsecured notes for approximately $191.3 million aggregate principal amount of Third Lien Notes, thereby reducing the outstanding principal amount of the 2022 Notes to $98.3 million as of September 30, 2015. At closing the Company paid all accrued and unpaid interest since the prior interest payment date in August 2015.

On November 6, 2012, the Company issued $750.0 million aggregate principal amount of its 8.875% senior notes due 2021 (the 2021 Notes), at a price to the initial purchasers of 99.247% of par. The net proceeds from the offering of approximately $725.6 million (after deducting the initial purchasers' discounts, commissions and offering expenses) were used to fund a portion of the cash consideration paid in the acquisition of two wholly-owned subsidiaries of Petro-Hunt Holdings, LLC and Pillar Holdings, LLC, which owned acreage prospective for the Bakken/Three Forks formations located in North Dakota, in Williams, Mountrail, McKenzie and Dunn Counties.

On January 14, 2013, the Company issued an additional $600.0 million aggregate principal amount of the 2021 Notes at a price to the initial purchasers of 105% of par. The net proceeds from the sale of the additional 2021 Notes of approximately $619.5 million (after the initial purchasers' premiums, commissions and offering expenses) were used to repay all of the then outstanding borrowings under the Senior Credit Agreement and for general corporate purposes, including funding a portion of the Company's 2013 capital expenditures program. These notes were issued as "additional notes" under the indenture governing the 2021 Notes and under the indenture are treated as a single series with substantially identical terms as the 2021 Notes previously issued.

The 2021 Notes bear interest at a rate of 8.875% per annum, payable semi-annually on May 15 and November 15 of each year, beginning on May 15, 2013. The Notes will mature on May 15, 2021. The 2021 Notes are senior unsecured obligations of the Company and are effectively subordinate to its secured debt, including secured debt under the Senior Credit Agreement, the Second Lien Notes and the Third Lien Notes and rank equally with all of its current and future senior indebtedness. The 2021 Notes are jointly and severally, fully and unconditionally guaranteed on a senior unsecured basis by the Company's existing 100% owned subsidiaries, except for the subsidiary, HK TMS, LLC. Halcón, the issuer of the 2021 Notes, has no material independent assets or operations apart from the assets and operations of its subsidiaries.

In conjunction with the issuance of the 2021 Notes, the Company recorded a discount of approximately $5.7 million to be amortized over the remaining life of the 2021 Notes using the effective interest method. The remaining unamortized discount was $1.6 million at September 30, 2015. In conjunction with the issuance of the additional 2021 Notes, the Company recorded a premium of approximately $30.0 million to be amortized over the remaining life of the additional 2021 Notes using the effective interest method. The remaining unamortized premium was $8.5 million at September 30, 2015.

During the second quarter of 2015, the Company entered into several exchange agreements with holders of the Company's 2021 Notes in which they agreed to exchange an aggregate $60.6 million principal amount of their senior notes for approximately 34.4 million shares of the Company's common stock, thereby reducing the aggregate principal amount of the 2021 Notes. The exchanges closed on

various dates from April 29, 2015 through May 15, 2015, at which time the Company also paid all accrued and unpaid interest since the prior interest payment date for the 2021 Notes. See "Senior Notes Exchanged for Common Stock" below for more details.

On September 10, 2015, the Company closed several separate, privately negotiated exchange agreements with holders of the Company's 2021 Notes in which they agreed to exchange an aggregate $774.7 million principal amount of their senior unsecured notes for approximately $503.6 million aggregate principal amount of Third Lien Notes, thereby reducing the outstanding principal amount of the 2021 Notes to $514.7 million as of September 30, 2015. At closing the Company paid all accrued and unpaid interest since the prior interest payment date in May 2015.

On July 16, 2012, the Company issued $750.0 million aggregate principal amount of 9.75% senior notes due 2020 issued at 98.646% of par (the 2020 Notes). The net proceeds from the offering were approximately $723.1 million after deducting the initial purchasers' discounts, commissions and offering expenses and were used to fund a portion of the cash consideration paid in the merger with GeoResources, Inc., and the acquisition of certain oil and gas leaseholds located in East Texas.

On December 19, 2013, the Company issued an additional $400.0 million aggregate principal amount of the 2020 Notes at a price to the initial purchasers of 102.750% of par. The net proceeds from the sale of the additional 2020 Notes of approximately $406.3 million (after the initial purchasers' fees, commissions and offering expenses) were used to repay a portion of the then outstanding borrowings under the Senior Credit Agreement. These notes were issued as "additional notes" under the indenture governing the 2020 Notes and under the indenture are treated as a single series with substantially identical terms as the 2020 Notes previously issued.

The 2020 Notes bear interest at a rate of 9.75% per annum, payable semi-annually on January 15 and July 15 of each year, beginning on January 15, 2013. The 2020 Notes will mature on July 15, 2020. The 2020 Notes are senior unsecured obligations of the Company and are effectively subordinate to its secured debt, including secured debt under the Senior Credit Agreement, the Second Lien Notes and the Third Lien Notes and rank equally with all of its current and future senior indebtedness. The 2020 Notes are jointly and severally, fully and unconditionally guaranteed on a senior unsecured basis by the Company's existing 100% owned subsidiaries, except for the subsidiary, HK TMS, LLC. Halcón, the issuer of the 2020 Notes, has no material independent assets or operations apart from the assets and operations of its subsidiaries.

In conjunction with the issuance of the 2020 Notes, the Company recorded a discount of approximately $10.2 million to be amortized over the remaining life of the 2020 Notes using the effective interest method. The remaining unamortized discount was $2.7 million at September 30, 2015. In conjunction with the issuance of the additional 2020 Notes, the Company recorded a premium of approximately $11.0 million to be amortized over the remaining life of the additional 2020 Notes using the effective interest method. The remaining unamortized premium was approximately $3.7 million at September 30, 2015.

During the second quarter of 2015, the Company entered into several exchange agreements with holders of the Company's 2020 Notes in which they agreed to exchange an aggregate $190.0 million principal amount of their senior notes for approximately 106.1 million shares of the Company's

common stock, thereby reducing the aggregate principal amount of the 2020 Notes. The exchanges closed on various dates from April 13, 2015 through May 4, 2015, at which time the Company also paid all accrued and unpaid interest since the prior interest payment date for the 2020 Notes. See "Senior Notes Exchanged for Common Stock" below for more details.

On September 10, 2015, the Company closed several separate, privately negotiated exchange agreements with holders of the Company's 2020 Notes in which they agreed to exchange an aggregate $497.2 million principal amount of their senior unsecured notes for approximately $323.1 million aggregate principal amount of Third Lien Notes, thereby reducing the outstanding principal amount of the 2020 Notes to $462.8 million as of September 30, 2015. At closing the Company paid all accrued and unpaid interest since the prior interest payment date in July 2015.

On February 8, 2012, the Company issued to HALRES, LLC (HALRES), a note in the principal amount of $275.0 million due 2017 (the Convertible Note) together with five year warrants (February 2012 Warrants) for an aggregate purchase price of $275.0 million. The Convertible Note bears interest at a rate of 8% per annum, payable quarterly on March 31, June 30, September 30 and December 31 of each year. Through the March 31, 2014 interest payment date, the Company was permitted to elect to pay the interest in kind, by adding to the principal of the Convertible Note, all or any portion of the interest due on the Convertible Note. The Company elected to pay the interest in kind on March 31, June 30 and September 30, 2012, and added $3.2 million, $5.7 million and $5.8 million of interest incurred, respectively, to the Convertible Note, increasing the principal amount to $289.7 million. The Company did not elect to pay-in-kind interest for the subsequent quarterly payments. The Convertible Note is a senior unsecured obligation of the Company.

On March 9, 2015, the Company entered into an amendment (the HALRES Note Amendment) to its Convertible Note. The HALRES Note Amendment extends the maturity date of the Convertible Note by three years, from February 8, 2017 to February 8, 2020. The Convertible Note originally provided for prepayment without premium or penalty at any time after February 8, 2014, at which time it also became convertible into shares of the Company's common stock at a conversion price of $4.50 per share. These dates have been extended pursuant to the HALRES Note Amendment and the conversion price has been adjusted, such that at any time after March 9, 2017, the Company may prepay the Convertible Note without premium or penalty, and HALRES may elect to convert all or any portion of unpaid principal and interest outstanding under the Convertible Note to shares of the Company's common stock at a conversion price of $2.44 per share, subject to adjustments for stock splits and other customary anti-dilution provisions as set forth in the Convertible Note. At the same time, the Company also entered into an amendment to the February 2012 Warrants (the Warrant Amendment) which extends the term of the February 2012 Warrants from February 8, 2017 to February 8, 2020 and adjusts the exercise price of the February 2012 Warrants from $4.50 to $2.44 per share.

In connection with the HALRES Note Amendment and the Warrant Amendment (the Amendments), the Company and HALRES also amended and restated the Registration Rights Agreement, dated February 8, 2012, as amended (the Amended Registration Rights Agreement), which provides for certain demand and piggyback registration rights for the shares of the Company's common stock issuable upon conversion of the Convertible Note and exercise of the February 2012 Warrants.

The Amendments were approved by the Company's stockholders on May 6, 2015, in accordance with the rules of the New York Stock Exchange.

The Company accounted for the HALRES Note Amendment as a debt extinguishment because the change in the fair value of the embedded conversion option immediately before and after the modification was at least 10% of the carrying amount of the original Convertible Note immediately prior to the modification. The $7.3 million difference between the unamortized original issuance discount of $18.6 million and the post-amendment discount of $25.9 million, net of $1.4 million of unamortized initial issuance costs, resulted in a net gain recorded in "Gain (loss) on extinguishment of Convertible Note and modification of February 2012 Warrants" in the unaudited condensed consolidated statements of operations. See Note 10, "Stockholders' Equity" for further discussion of the Warrant Amendment. The remaining unamortized discount was $24.2 million at September 30, 2015.

During the second quarter of 2015, the Company entered into several exchange agreements with existing holders of the Company's senior unsecured notes in which the holders agreed to exchange an aggregate $258.0 million principal amount of their senior notes for approximately 144.8 million shares of the Company's common stock.

On May 7, 2015, the Company entered into an exchange agreement with Union Square Park Partners, L.P., a holder of the Company's 2022 Notes and 2021 Notes, pursuant to which it agreed to exchange approximately $5.8 million principal amount of such notes for approximately 3.5 million shares of the Company's common stock, resulting in an effective exchange price of $1.70 per share. Of the aggregate $5.8 million principal amount of senior notes to be exchanged by the holders, approximately $2.0 million is principal amount of 2022 Notes and approximately $3.8 million is principal amount of 2021 Notes. The exchange closed on May 15, 2015, at which time the Company also paid all accrued and unpaid interest on the notes since the prior interest payment date for each of the 2022 Notes and 2021 Notes.

On April 24, 2015, the Company entered into an exchange agreement with several investment funds advised by Pioneer Investments, each of which is a holder of the Company's 2020 Notes, 2021 Notes and 2022 Notes (the Senior Notes), pursuant to which the funds agreed to exchange an aggregate $25.0 million principal amount of the Senior Notes for approximately 14.8 million shares of the Company's common stock, resulting in an effective exchange price of $1.69 per share. Of the aggregate $25.0 million principal amount of Senior Notes to be exchanged by the holders, approximately $2.8 million is principal amount of 2020 Notes, approximately $16.8 million is principal amount of 2021 Notes and approximately $5.4 million is principal amount of 2022 Notes. The exchanges closed on various dates from April 30, 2015 through May 4, 2015, at which time the Company also paid all accrued and unpaid interest since the relevant prior interest payment dates for each of the Senior Notes.

On April 22, 2015, the Company entered into an exchange agreement with J.P. Morgan Securities LLC, a holder of the Company's 2021 Notes, pursuant to which it agreed to exchange approximately $40.0 million principal amount of such notes for approximately 22.2 million shares of the Company's common stock, resulting in an effective exchange price of $1.80 per share. The exchange closed on April 29, 2015, at which time the Company also paid all accrued and unpaid interest on the notes since the prior interest payment date in November 2014.

On April 15, 2015, the Company entered into an exchange agreement with Goldman Sachs Asset Management, L.P., on behalf of certain of its funds and accounts which hold the Company's 2020 Notes, pursuant to which the holders agreed to exchange approximately $70.7 million principal amount of such notes for approximately 38.8 million shares of the Company's common stock, resulting in an effective exchange price of $1.82 per share. The exchanges closed on various dates from April 22, 2015 through April 28, 2015, at which time the Company also paid all accrued and unpaid interest on the notes since the prior interest payment date in January 2015.

On April 7, 2015, the Company entered into an exchange agreement with two investment funds advised by Franklin Templeton Investments, each of which is an existing holder of the Company's 2020 Notes, pursuant to which the funds agreed to exchange an aggregate $116.5 million principal amount of such notes for approximately 65.5 million shares of the Company's common stock, resulting in an effective exchange price of $1.78 per share. The exchange closed on April 13, 2015, at which time the Company also paid all accrued and unpaid interest on the notes since the prior interest payment date in January 2015.

The Company recorded the issuance of common shares at fair value on the various dates the debt for equity exchanges occurred and also recognized a $22.8 million net gain on the extinguishment of debt, as a $26.6 million gain on the exchanges was partially offset by the writedown of $3.8 million associated with related issuance costs and discounts and premiums for the respective notes. The net gain is recorded in "Gain (loss) on extinguishment of debt" in the unaudited condensed consolidated statements of operations.

The Company capitalizes certain direct costs associated with the issuance of long-term debt and amortizes such costs over the lives of the respective debt. The Company capitalized $25.8 million associated with the issuance of the Second Lien Notes, the Third Lien Notes and amendments to its Senior Credit Agreement. The Company expensed $32.0 million of debt issuance costs in conjunction with the issuance of the Third Lien Notes, the debt for equity exchanges, the debt extinguishment for the HALRES Note Amendment, and decreases in the Company's borrowing base under the Senior Credit Agreement. At September 30, 2015 and December 31, 2014, the Company had approximately $42.6 million and $55.9 million, respectively, of unamortized debt issuance costs.

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.

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, 2015 and December 31, 2014. 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 the nine months ended September 30, 2015 or the year ended December 31, 2014.

Derivative contracts listed above as Level 2 include collars, swaps and swaptions 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" in the Company's 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 6, "Derivative and Hedging Activities" for additional discussion of derivatives.

Derivative contracts listed above as Level 3 include extendable collars that are carried at fair value. The significant unobservable inputs for these Level 3 contracts include unpublished forward strip prices

and market volatilities. The following table sets forth a reconciliation of changes in the fair value of the Company's extendable collar contracts classified as Level 3 in the fair value hierarchy:

As of September 30, 2015 and December 31, 2014, the Company's derivative contracts were with major financial 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, 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 approximates carrying value because the interest rates approximate current market rates. The following table presents the estimated fair values of the Company's fixed interest rate, long-term debt instruments as of September 30, 2015 and December 31, 2014 (excluding discounts and premiums):

The fair value of the Company's senior notes was calculated based on quoted market prices from trades of such debt, which are considered Level 2 criteria.

During the second quarter of 2015, the Company entered into several exchange agreements with holders of the company's senior unsecured notes in which they agreed to exchange their senior notes for shares of the Company's common stock. The fair value of the common shares issued was determined by using quoted market prices of the Company's common stock, which is considered Level 1 criteria in the fair value hierarchy. See Note 4, "Long-term Debt," for further discussion of the exchanges and the net gain recorded on the transactions.

As discussed in Note 4, "Long-term Debt" and in Note 10, "Stockholders' Equity," on May 6, 2015, the HALRES Note Amendment and the Warrant Amendment became effective. The fair value estimates for the Convertible Note and the February 2012 Warrants include the use of observable inputs such as the Company's stock price, expected volatility, and credit spread and the risk-free rate. The use of these observable inputs results in the fair value estimates being classified as Level 2.

During the nine months ended September 30, 2014, the Company recorded a non-cash impairment charge of $3.8 million related to its gas gathering systems and other operating assets. See Note 1, "Financial Statement Presentation," for a discussion of the valuation approach used and the classification of the estimate within the fair value hierarchy.

On June 16, 2014, the Company entered into a transaction to develop its Tuscaloosa Marine Shale assets with funds and accounts managed by affiliates of Apollo Global Management, LLC and on June 1, 2015 amended this agreement. See Note 9, "Mezzanine Equity," for a discussion of the valuation approach used to allocate the initial investment proceeds to the transaction's components, for the valuation approach used to fair value the transaction's components upon the amendment, for the classification of the estimates within the fair value hierarchy, and for a reconciliation of the beginning and ending liability balances for the redeemable non-controlling interest, the tranche rights and the embedded derivative.

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; consequently, the Company has designated these liabilities as Level 3. See Note 7, "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 economically 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 and natural gas production. The Company generally hedges a substantial, but varying, portion of anticipated oil and natural gas 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 institutions deemed by management as competent and competitive market makers. 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.

At September 30, 2015 and December 31, 2014, the Company's crude oil and natural gas derivative positions consisted of swaps, swaptions, costless put/call "collars," and extendable costless collars. 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. Swaptions are swap contracts that may be extended annually at the option of the counterparty on a designated date. 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. Extendable collars are costless put/call contracts that may be extended annually at the option of the counterparty on a designated date. 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 all payments and receipts on settled derivative contracts, in "Net gain (loss) on derivative contracts" on the unaudited condensed consolidated statements of operations.

At September 30, 2015, the Company had 77 open commodity derivative contracts summarized in the following tables: four natural gas collar arrangements, 44 crude oil collar arrangements, 18 crude oil swaps, eight crude oil swaptions and three crude oil extendable collars.

At December 31, 2014, the Company had 72 open commodity derivative contracts summarized in the following tables: four natural gas collar arrangements, 42 crude oil collar arrangements, 16 crude oil swaps, eight crude oil swaptions and two crude oil extendable collars.

All derivative contracts are recorded at fair market value in accordance with 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 as of September 30, 2015 and December 31, 2014:

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:

		Amount of gain or (loss) recognized in income on derivative contracts for the Three Months Ended September 30,					Amount of gain or (loss) recognized in income on derivative contracts for the Nine Months Ended September 30,

	Location of gain or (loss) recognized in income on derivative contracts
Derivatives not designated as hedging contracts under ASC 815		2015		2014			2015			2014
		(In thousands)					(In thousands)
Commodity contracts:
Unrealized gain (loss) on commodity contracts	Other income (expenses)—net gain (loss) on derivative contracts	$	89,741	$	169,713		$	(93,972	)	$	36,900
Realized gain (loss) on commodity contracts	Other income (expenses)—net gain (loss) on derivative contracts		114,880		(6,426	)		310,777			(28,311	)

Total net gain (loss) on derivative contracts		$	204,621	$	163,287		$	216,805		$	8,589

At September 30, 2015 and December 31, 2014, the Company had the following open crude oil and natural gas derivative contracts:

			September 30, 2015

					Floors				Ceilings
Period	Instrument	Commodity	Volume in Mmbtu's/ Bbl's		Price / Price Range		Weighted Average Price		Price / Price Range		Weighted Average Price
October 2015 - December 2015⁽¹⁾	Collars	Crude Oil		2,346,000	$	82.50 - 90.00	$	86.42	$	90.00 - 100.25	$	93.39
October 2015 - December 2015	Collars	Natural Gas		1,610,000		4.00		4.00		4.55 - 4.85		4.68
October 2015 - December 2015⁽²⁾	Swaps	Crude Oil		460,000		91.00 - 92.75		91.76
January 2016 - June 2016	Collars	Crude Oil		182,000		90.00		90.00		96.85		96.85
January 2016 - December 2016	Collars	Natural Gas		732,000		4.00		4.00		4.22		4.22
January 2016 - December 2016⁽³⁾	Collars	Crude Oil		4,392,000		60.00 - 90.00		71.91		64.00 - 95.10		77.71
January 2016 - December 2016⁽⁴⁾	Swaps	Crude Oil		4,758,000		62.00 - 91.73		85.43
January 2017 - December 2017	Collars	Crude Oil		1,368,750		50.00 - 60.00		57.33		70.00 - 76.84		74.16

			December 31, 2014

					Floors				Ceilings
Period	Instrument	Commodity	Volume in Mmbtu's/ Bbl's		Price / Price Range		Weighted Average Price		Price / Price Range		Weighted Average Price
January 2015 - June 2015	Collars	Crude Oil		1,583,750	$	85.00 - 90.00	$	86.29	$	91.00 - 98.50	$	93.14
January 2015 - December 2015⁽¹⁾	Collars	Crude Oil		6,205,000		82.50 - 90.00		86.47		90.00 - 100.25		94.39
January 2015 - December 2015	Collars	Natural Gas		6,387,500		4.00		4.00		4.55 - 4.85		4.68
January 2015 - December 2015⁽²⁾	Swaps	Crude Oil		1,825,000		91.00 - 92.75		91.76
March 2015 - December 2015	Collars	Crude Oil		306,000		87.50		87.50		92.50		92.50
April 2015 - December 2015	Collars	Crude Oil		412,500		87.50		87.50		92.50		92.50
July 2015 - December 2015	Collars	Crude Oil		1,104,000		85.00 - 87.50		85.83		90.00 - 92.50		90.92
January 2016 - June 2016	Collars	Crude Oil		182,000		90.00		90.00		96.85		96.85
January 2016 - December 2016	Collars	Crude Oil		1,830,000		87.50 - 90.00		88.55		92.70 - 95.10		93.84
January 2016 - December 2016	Collars	Natural Gas		732,000		4.00		4.00		4.22		4.22
January 2016 - December 2016⁽⁴⁾	Swaps	Crude Oil		4,026,000		88.00 - 91.73		89.65

(1): Includes an outstanding crude oil collar which may be extended by the counterparty at a floor of $85.00 per Bbl and a ceiling of $96.20 per Bbl for a total of 732,000 Bbls for the year ended December 31, 2016. Also includes an outstanding crude oil collar which may be extended by the counterparty at a floor of $85.00 per Bbl and a ceiling of $96.00 per Bbl for a total of 366,000 Bbls for the year ended December 31, 2016.
(2): Includes an outstanding crude oil swap which may be extended by the counterparty at a price of $91.25 per Bbl for 732,000 Bbls for the year ended December 31, 2016. Also includes certain outstanding crude oil swaps which may be extended by the counterparty at a price of $91.00 per Bbl totaling 366,000 Bbls for the year ended December 31, 2016.
(3): Includes an outstanding crude oil collar which may be extended by the counterparty at a floor of $60.00 per Bbl and a ceiling of $75.00 per Bbl for a total of 365,000 Bbls for the year ended December 31, 2017.
(4): Includes an outstanding crude oil swap which may be extended by the counterparty at a price of $88.25 per Bbl for a total of 730,000 Bbls for the year ended December 31, 2017. Also includes certain outstanding crude oil swaps which may be extended by the counterparty at a price of $88.00 per Bbl totaling 912,500 Bbls for the year ended December 31, 2017. Includes an outstanding crude oil swap which may be extended by the counterparty at a price of $88.87 per Bbl totaling 547,500 Bbls for the year ended December 31, 2017.

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, 2015 and December 31, 2014:

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 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 gas gathering systems 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 nine months ended September 30, 2015 (in thousands, inclusive of the current portion):

The Company leases corporate office space in Houston, Texas; and Denver, Colorado as well as a number of other field office locations. Rent expense was approximately $6.4 million and $6.0 million for the nine months ended September 30, 2015 and 2014, respectively. As of September 30, 2015, the amount of commitments under office and equipment lease agreements is consistent with the levels at December 31, 2014, as disclosed in the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2014, approximating $53.2 million in the aggregate, and containing various expiration dates through 2024.

In addition, the Company has commitments for certain equipment under long-term operating lease agreements, namely drilling rigs as well as pipeline and well equipment, with various expiration dates through 2018. In January 2015, the Company made the decision to early terminate a drilling rig contract in response to the recent decline in crude oil prices, and as such, the Company incurred an early termination fee of $6.0 million, paid over the first half of 2015. If certain requirements are not met by two separate trigger dates, the first being January 1, 2017 and the second being January 12, 2020, the Company may incur up to an additional $3.0 million in connection with this drilling rig contract. In addition, the Company has a new drilling rig commitment that began on May 1, 2015, for which the Company is incurring a stacking fee of $17,000 per day. The contract term for this drilling rig

commitment extends through the second quarter of 2018. Early termination of the Company's other drilling rig commitments would result in termination penalties approximating $34.3 million, which would be in lieu of the remaining $50.9 million of drilling rig commitments as of September 30, 2015.

The Company has entered into various long-term gathering, transportation and sales contracts with respect to production from the Bakken/Three Forks formations in North Dakota. As of September 30, 2015, the Company had in place ten long-term crude oil contracts and six long-term natural gas contracts in this area. Under the terms of these contracts, the Company has committed a substantial portion of its Bakken/Three Forks production for periods ranging from one to ten years from the date of first production. The sales prices under these contracts are based on posted market rates. Historically, the Company has been able to meet its delivery commitments.

On December 20, 2013, the Company entered into a carry and earning agreement, as amended (the Agreement) with an independent third party (Seller) associated with the acquisition of certain properties believed to be prospective for the Tuscaloosa Marine Shale (TMS), primarily in Wilkinson County, Mississippi and in West Feliciana and East Feliciana Parishes, Louisiana. The Agreement required the Company to fund up to $189.4 million (the Carry Amount) in exchange for approximately 117,870 net acres. The Company paid $62.5 million of the Carry Amount at closing on February 28, 2014 and the remaining $126.9 million during the three months ended June 30, 2014, reflected as "Advance on carried interest" in the accompanying unaudited condensed consolidating statements of cash flows. The Carry Amount is to be used by the Seller to fund wells prospective for the TMS to be drilled by the Seller (the Carry Wells) on the Seller's retained acreage. As part of the transaction, the Company will also receive a 5% working interest in the Carry Wells. As of December 31, 2014, approximately $71.9 million of the Carry Amount remained in escrow to be spent by the Seller and as of September 30, 2015, the Carry Amount was fully expended.

On June 16, 2014, the Company entered into a transaction to develop its TMS assets with funds and accounts managed by affiliates of Apollo Global Management, LLC. See Note 9, "Mezzanine Equity," for a discussion of the drilling obligation associated with the transaction.

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 its 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 unaudited condensed consolidated operating results, financial position or cash flows.

On June 16, 2014, funds and accounts managed by affiliates of Apollo Global Management, LLC (Apollo) contributed $150 million in cash to HK TMS, LLC, a wholly owned Delaware limited liability company (HK TMS), that, as of June 16, 2014 held all of the Company's undeveloped acreage in Mississippi and Louisiana that management believes is prospective for the TMS formation, in exchange for the issuance by HK TMS of 150,000 preferred shares. At the closing, the Company also contributed $50 million in cash to HK TMS. Holders of the HK TMS preferred shares will receive quarterly cash dividends of 8% cumulative perpetual per annum, subject to HK TMS' option to pay such dividends

"in-kind" through the issuance of additional preferred shares. The preferred shares will be automatically redeemed and cancelled when the holders receive cash dividends and distributions on the preferred shares equating to the greater of a 12% annual rate of return plus principal and 1.25 times their investment plus applicable fees (the Redemption Price), subject to adjustment under certain circumstances. The preferred shares have a liquidation preference in the event of dissolution in an amount equal to the Redemption Price plus any unpaid dividends not otherwise included in the calculation of the Redemption Price through the date of liquidation payment. HK TMS may also redeem the preferred shares at any time after December 31, 2016 by paying the Redemption Price, or may be required to redeem the preferred shares for the Redemption Price plus certain fees under certain circumstances.

On June 1, 2015, HK TMS and Apollo entered into an amendment to the original agreement (the HK TMS Amendment) which, among other things, i) commits HK TMS to drill a minimum of 6.5 net wells in each of the five consecutive twelve month periods beginning December 31, 2015 and ii) allows for the redemption of preferred shares at the Redemption Price between March 1, 2016 and June 30, 2016 at the election of Apollo to the extent there is available cash above the minimum cash balance, which is discussed further below. For any commitment period in which HK TMS does not meet its drilling obligation, HK TMS must use available cash, above the minimum cash balance, to redeem preferred shares at the Redemption Price.

The preferred shares have been classified as "Redeemable noncontrolling interest" and included in "Mezzanine equity" between total liabilities and stockholders' equity on the unaudited condensed consolidated balance sheets pursuant to ASC 480-10-S99-3A. The preferred shares, while not currently redeemable, are considered probable of becoming redeemable and therefore will be subsequently remeasured each reporting period by accreting the initial value to the estimated required redemption value through March 1, 2016. The accretion is presented as a deemed dividend and recorded in "Redeemable noncontrolling interest" on the unaudited condensed consolidated balance sheet and within "Preferred dividends and accretion on redeemable noncontrolling interest" on the unaudited condensed consolidated statements of operations. In accordance with ASC 480-10-S99-3A, an adjustment to the carrying amount presented in "Mezzanine equity" will be recognized as charges against retained earnings and will reduce income available to common shareholders in the calculation of earnings per share. Adjustments to the carrying amount may not be necessary if the application of ASC No. 810, Consolidation (ASC 810) results in a noncontrolling interest balance in excess of what is required pursuant to ASC 480-10-S99-3A.

Under certain circumstances, Apollo could have acquired up to an additional 250,000 preferred shares of HK TMS on the same terms, with HK TMS receiving up to an additional $250 million in cash proceeds (Tranche Rights). The Tranche Rights were recognized separately as a liability instrument within "Other noncurrent liabilities" in the unaudited condensed consolidated balance sheets, as of December 31, 2014, in accordance with ASC 480 as the shares underlying the Tranche Rights were redeemable equity instruments. The Tranche Rights were subsequently remeasured at fair value each reporting period in accordance with ASC 480, with fair value changes recorded in "Interest expense and other, net" on the unaudited condensed consolidated statements of operations. In March 2015, Apollo delivered a withdrawal notice to HK TMS indicating their election not to participate in the Tranche Rights (the Withdrawal Notice). As such, the fair value of the liability associated with the Tranche Rights was expensed during the three months ended March 31, 2015. Upon issuance of the Withdrawal Notice, HK TMS incurs a fee escalating from $2.50 per share to $20.00 per share for the

next eight full fiscal quarters for any preferred shares then outstanding, which began in the quarter ended June 30, 2015 (the Withdrawal Exit Fee). The Withdrawal Exit Fee is payable upon redemption of the preferred shares. As of September 30, 2015, HK TMS incurred Withdrawal Exit Fees of $1.2 million. The Withdrawal Exit Fees were recorded at fair value within "Other noncurrent liabilities" on the unaudited condensed consolidated balance sheets.

In conjunction with the issuance of the preferred shares, HK TMS conveyed a 4.0% overriding royalty interest (ORRI), subject to reduction to 2.0% under certain circumstances, in 75 net wells to be drilled and completed on its TMS acreage. The number of wells subject to the ORRI would have increased to the extent that Apollo subscribed for additional preferred shares, with a maximum of 200 net operated wells subject to such ORRI if Apollo subscribed for the full additional 250,000 preferred shares. However, upon issuance of the Withdrawal Notice, Apollo forfeited the rights to the ORRI in the additional 125 wells. The ORRI has been recognized separately as a conveyance of oil and natural gas properties in "Unevaluated properties" on the unaudited condensed consolidated balance sheets.

As part of the transaction, there are certain restrictions on the transfer of assets, including cash, to the Company from HK TMS. HK TMS is required to maintain a minimum cash balance equal to two quarterly dividend payments, of approximately $3.0 million each, plus $10.0 million, which is presented on the unaudited condensed consolidated balance sheets in "Restricted cash." Additionally, the quarterly 8% dividends paid to holders of the HK TMS preferred shares have priority over other cash distributions. No dividends shall be paid to the Company from HK TMS prior to December 31, 2016. HK TMS is restricted from transferring more than 20% of its maximum net acres and from transferring any assets exceeding 20% of HK TMS's proved reserves at any one time without approval from the Company and Apollo. Finally, proceeds from any such transfers of acres or other assets must be used for HK TMS's capital or operating expenditures, or to redeem preferred shares.

For purposes of estimating the fair values of the original and amended transaction components, an income approach was used that estimated fair value based on the anticipated cash flows associated with the Company's proved reserves, discounted using a weighted average cost of capital rate. The estimation of the fair value of these components includes the use of unobservable inputs, such as estimates of proved reserves, the weighted average cost of capital (discount rate), estimated future revenues, and estimated future capital and operating costs. The use of these unobservable inputs results in the fair value estimates being classified as Level 3. Although the Company believes the assumptions and estimates used in the fair value calculation of the original and amended transaction components are reasonable and appropriate, different assumptions and estimates could materially impact the analysis and resulting conclusions. The assumptions used in estimating the fair value of the original and amended transaction components are inherently uncertain and require management judgment.

The following table sets forth a reconciliation of the changes in fair value of the Tranche Rights and embedded derivative classified as Level 3 in the fair value hierarchy (in thousands):

The Company recorded the following activity related to the preferred shares recorded in "Mezzanine equity" for the period presented (in thousands, except share amounts):

For the nine months ended September 30, 2015, HK TMS issued 9,340 additional preferred shares to Apollo for dividends paid-in-kind. These dividends are presented within "Preferred dividends and accretion on redeemable noncontrolling interest" on the unaudited condensed consolidated statements of operations. Upon the election of in-kind dividends, HK TMS must pay a fee of $5.00 per preferred share then outstanding (PIK Exit Fee). Such fees will be due upon redemption of the preferred shares. As of September 30, 2015, HK TMS incurred PIK Exit Fees totaling $3.1 million, which were recorded at fair value within "Other noncurrent liabilities" on the unaudited condensed consolidated balance sheets.

On June 18, 2013, the Company completed its offering of 345,000 shares of its 5.75% Series A Convertible Perpetual Preferred Stock (the Series A Preferred Stock) at a public offering price of $1,000 per share (the Liquidation Preference). The net proceeds to the Company were approximately $335.2 million, after deducting the underwriting discount and offering expenses. The Company used the net proceeds to repay a portion of the then outstanding borrowings under its Senior Credit Agreement.

Holders of the Series A Preferred Stock are entitled to receive, when, as and if declared by the Company's Board of Directors, cumulative dividends at the rate of 5.75% per annum (the Dividend Rate) on the Liquidation Preference per share of the Series A Preferred Stock, payable quarterly in arrears on each dividend payment date. Dividends may be paid in cash or, where freely transferable by any non-affiliate recipient thereof, in common stock of the Company, or a combination thereof, and are payable on March 1, June 1, September 1 and December 1 of each year. During the nine months ended September 30, 2015, the Company incurred cumulative, declared dividends of $14.5 million by paying $4.7 million in cash and issuing approximately 6.8 million shares of common stock. As of September 30, 2015, cumulative, undeclared dividends on the Series A Preferred Stock amounted to approximately $1.2 million.

The Series A Preferred Stock has no maturity date, is not redeemable by the Company at any time, and will remain outstanding unless converted by the holders or mandatorily converted by the Company. Each share of Series A Preferred Stock is convertible, at the holder's option at any time, into approximately 162.4431 shares of common stock of the Company (which is equivalent to a

conversion price of approximately $6.16 per share), subject to specified adjustments as set forth in the Series A Designation. Based on the initial conversion rate and preferred shares outstanding, approximately 56.0 million shares of common stock of the Company would have been issuable upon conversion of all the shares of Series A Preferred Stock. On or after June 6, 2018, the Company may, at its option, give notice of its election to cause all outstanding shares of the Series A Preferred Stock to be automatically converted into shares of common stock of the Company at the conversion rate (as defined in the Series A Designation), if the closing sale price of the Company's common stock equals or exceeds 150% of the conversion price for at least 20 trading days in a period of 30 consecutive trading days. As of September 30, 2015, 100,066 shares of Series A Preferred Stock have been converted into approximately 16.3 million shares of common stock.

If the Company undergoes a fundamental change (as defined in the Series A Designation) and a holder converts its shares of the Series A Preferred Stock at any time beginning at the opening of business on the trading day immediately following the effective date of such fundamental change and ending at the close of business on the 30th trading day immediately following such effective date, the holder will receive, for each share of the Series A Preferred Stock surrendered for conversion, a number of shares of common stock of the Company equal to the greater of: (1) the sum of (i) the conversion rate and (ii) the make-whole premium, if any, as described in the Series A Designation; and (2) the conversion rate which will be increased to equal (i) the sum of the $1,000 liquidation preference plus all accumulated and unpaid dividends to, but excluding, the settlement date for such conversion, divided by (ii) the average of the closing sale prices of the Company's common stock for the five consecutive trading days ending on the third business day prior to such settlement date; provided that the prevailing conversion rate as adjusted pursuant to this will not exceed 292.3977 shares of common stock of the Company per share of the Series A Preferred Stock (subject to adjustment in the same manner as the conversion rate).

Except as required by Delaware law, holders of the Series A Preferred Stock will have no voting rights unless dividends are in arrears and unpaid for six or more quarterly periods. Until such arrearage is paid in full, the holders (voting as a single class with the holders of any other preferred shares having similar voting rights) will be entitled to elect two additional directors and the number of directors on the Company's Board of Directors will increase by that same number.

During the second quarter of 2015, the Company entered into several exchange agreements with holders of the Company's senior unsecured notes in which they agreed to exchange an aggregate $258.0 million principal amount of their senior notes for approximately 144.8 million shares of the Company's common stock. The Company recorded the issuance of common shares at fair value on the various dates the debt for equity exchanges occurred.

On March 18, 2015, the Company entered into an Equity Distribution Agreement (the Equity Distribution Agreement) with BMO Capital Markets Corp., Jefferies LLC and MLV & Co. LLC (collectively, the Managers). Pursuant to the terms of the Equity Distribution Agreement, the Company may sell, from time to time through the Managers, shares of its common stock having an aggregate offering price of up to $150 million (the Shares). Sales of the Shares, if any, will be made by means of ordinary brokers' transactions through the facilities of the New York Stock Exchange at market prices, or as otherwise agreed by the Company and the Managers. For the nine months ended September 30,

2015, the Company sold approximately 9.4 million shares for net proceeds of approximately $15.1 million, after deducting offering expenses. The shares sold have been registered under the Securities Act pursuant to a Registration Statement on Form S-3 (No. 333-188640), which was filed with the SEC and became effective March 13, 2015. The Company plans to use any net proceeds from the offering to repay a portion of outstanding borrowings under its Senior Credit Agreement and for general corporate purposes.

On May 22, 2014, with stockholder approval, the Company filed a Certificate of Amendment of the Amended and Restated Certificate of Incorporation with the Delaware Secretary of State to increase its authorized common stock by approximately 670.0 million shares for a total of 1.34 billion authorized shares of common stock.

In February 2012, in conjunction with the issuance of the Convertible Note, the Company issued warrants to purchase 36.7 million shares of the Company's common stock at an exercise price of $4.50 per share of common stock, which the Company refers to as the February 2012 Warrants. The Company allocated $43.6 million to the February 2012 Warrants which is reflected in additional paid-in capital in stockholders' equity, net of $0.6 million in issuance costs. The February 2012 Warrants entitled the holders to exercise the warrants in whole or in part at any time prior to the expiration date of February 8, 2017.

On March 9, 2015, in conjunction with the HALRES Note Amendment, the Company entered into an amendment to the February 2012 Warrants, the Warrant Amendment, which extends the term of the February 2012 Warrants from February 8, 2017 to February 8, 2020 and adjusts the exercise price of the February 2012 Warrants from $4.50 to $2.44 per share. The Amendments were approved by the Company's stockholders on May 6, 2015, in accordance with the rules of the New York Stock Exchange. The Company expensed approximately $14.1 million for the change in the fair value of the February 2012 Warrants immediately before and after the Warrant Amendment in "Gain (loss) on extinguishment of Convertible Note and modification of February 2012 Warrants" on the unaudited condensed consolidated statements of operations. See Note 4, "Long-term debt," for further discussion of the Amendments.

On May 8, 2006, the Company's stockholders first approved the 2006 Long-Term Incentive Plan (the Plan). On May 6, 2015, shareholders last approved an increase in authorized shares under the Plan from 41.5 million to 81.5 million. As of September 30, 2015 and December 31, 2014, a maximum of 44.0 million and 5.1 million shares of common stock, respectively, remained reserved for issuance under the Plan.

The Company accounts for share-based payment accruals under authoritative guidance on stock compensation, as set forth in ASC 718. The guidance requires all share-based payments to employees and directors, including grants of performance units, stock options, and restricted stock, to be recognized in the financial statements based on their fair values.

For the three and nine months ended September 30, 2015, the Company recognized $3.0 million and $11.2 million, respectively, of share-based compensation expense. For the three and nine months

ended September 30, 2014, the Company recognized $4.6 million and $13.8 million, respectively, of share-based compensation expense. These were recorded as a component of "General and administrative" on the unaudited condensed consolidated statements of operations.

As of September 30, 2015 and 2014, the Company had outstanding performance share units (PSU) under the Plan covering 1.6 million shares of common stock granted to senior management of the Company in 2014. The PSU provides that the number of shares of common stock received upon vesting will vary if the market price of the Company's common stock exceeds certain pre-established target thresholds as measured by the average of the adjusted closing price of a share of the Company's common stock during the sixty trading days preceding the third anniversary of issuance, or the measurement date. The PSU utilizes $4.00 as the floor price, below which the PSU will not vest and will expire. If the average market price at the measurement date is equal to $4.00, the PSU will vest and represent the right to receive 50% of the number of shares of common stock underlying the PSU. At $7.00, the PSU will vest and represent the right to receive the full number of shares of common stock underlying the PSU; and at $10.00, the PSU will vest and represent the right to receive 200% of the number of shares of common stock underlying the PSU. All stock price targets are subject to customary adjustments based upon changes in the Company's capital structure. In the event the average market price falls between targeted price thresholds, the PSU will represent the right to receive a proportionate number of shares. The Company has reserved for issuance under the Plan the maximum number of shares that participants might have the right to receive upon vesting of the PSU, or 3.2 million shares of common stock.

At September 30, 2015, the Company had $2.3 million of unrecognized compensation expense related to non-vested PSU to be recognized over a weighted-average period of 1.4 years. At September 30, 2014, the Company had $4.0 million of unrecognized compensation expense related to non-vested PSU to be recognized over a weighted-average period of 2.4 years.

During the nine months ended September 30, 2015, the Company granted stock options under the Plan covering 3.6 million shares of common stock to employees of the Company. These stock options have exercise prices ranging from $1.57 to $1.97 with a weighted average exercise price of $1.92. 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. At September 30, 2015, the Company had $6.6 million of unrecognized compensation expense related to non-vested stock options to be recognized over a weighted-average period of 1.0 years.

During the nine months ended September 30, 2014, the Company granted stock options under the Plan covering 6.2 million shares of common stock to employees of the Company. The stock options have exercise prices ranging from $3.67 to $7.42 with a weighted average exercise price of $3.70. 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. At September 30, 2014, the Company had $13.3 million of unrecognized compensation expense related to non-vested stock options to be recognized over a weighted-average period of 1.1 years.

During the nine months ended September 30, 2015, the Company granted 2.4 million shares of restricted stock under the Plan to directors and employees of the Company. These restricted shares were granted at prices ranging from $1.22 to $1.97 with a weighted average price of $1.74. Employee shares 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. At September 30, 2015, the Company had $9.7 million of unrecognized compensation expense related to non-vested restricted stock awards to be recognized over a weighted-average period of 1.0 years.

During the nine months ended September 30, 2014, the Company granted 3.9 million shares of restricted stock under the Plan to directors and employees of the Company. These restricted shares were granted at prices ranging from $3.67 to $7.42 with a weighted average price of $3.85. Employee shares 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. At September 30, 2014, the Company had $13.7 million of unrecognized compensation expense related to non-vested restricted stock awards to be recognized over a weighted-average period of 1.2 years.

Under guidance contained in ASC 740, deferred taxes are determined by applying the provisions of enacted tax laws and rates for the jurisdictions in which the Company operates to the estimated future tax effects of the differences between the tax basis of assets and liabilities and their reported amounts in the Company's financial statements. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

In assessing the need for a valuation allowance on the Company's deferred tax assets, the Company considers possible sources of taxable income that may be available to realize the benefit of deferred tax assets, including projected future taxable income, the reversal of existing temporary differences, taxable income in carryback years and available tax planning strategies. The Company considers all available evidence (both positive and negative) in determining whether a valuation allowance is required. A significant item of objective negative evidence considered was the cumulative book loss over the three-year period ended December 31, 2014 driven primarily by the full cost ceiling impairments over that period, which limits the ability to consider other subjective evidence such as the Company's anticipated future growth. Based upon the evaluation of the available evidence the Company continued to record a valuation allowance against its net deferred tax assets as of September 30, 2015.

The Company recorded an income tax provision of $6.2 million on a pre-tax loss of $1.5 billion for the nine months ended September 30, 2015 primarily due to the valuation allowance partially offset by estimated alternative minimum tax of $5.1 million and Texas franchise tax of $1.1 million. For the nine months ended September 30, 2014, the Company recorded an income tax benefit of $1.3 million on pre-tax income of $55.9 million due to the valuation allowance offset by expected refunds from the filing of certain prior year tax returns during the three months ended September 30, 2014.

During the first quarter of 2014, the Internal Revenue Service commenced an audit of GeoResources' tax returns for the tax years ending December 31, 2010 through August 1, 2012. The audit closed during April 2015 resulting in a favorable adjustment to the Company of $0.1 million.

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,

	2015		2014		2015			2014
Basic:
Net income (loss) available to common stockholders	$	123,528	$	186,853	$	(1,582,246	)	$	35,597



Weighted average basic number of common shares outstanding		586,053		416,470		517,624			415,264

Basic net income (loss) per share of common stock	$	0.21	$	0.45	$	(3.06	)	$	0.09



Diluted:
Net income (loss) available to common stockholders	$	123,528	$	186,853	$	(1,582,246	)	$	35,597



Net income from assumed conversions		8,860		9,004		—			—

Net income (loss) available to common stockholders after assumed conversions	$	132,388	$	195,857	$	(1,582,246	)	$	35,597



Weighted average basic number of common shares outstanding		586,053		416,470		517,624			415,264
Common stock equivalent shares representing shares issuable upon:
Exercise of stock options		Anti-dilutive		741		Anti-dilutive			452
Exercise of February 2012 Warrants		Anti-dilutive		7,549		Anti-dilutive			5,226
Vesting of restricted shares		Anti-dilutive		2,609		Anti-dilutive			1,608
Vesting of performance units		—		463		—			483
Conversion of Convertible Note		118,717		64,371		Anti-dilutive			Anti-dilutive
Conversion of Series A preferred stock		50,012		56,043		Anti-dilutive			Anti-dilutive

Weighted average diluted number of common shares outstanding		754,782		548,246		517,624			423,033

Diluted net income (loss) per share of common stock	$	0.18	$	0.36	$	(3.06	)	$	0.08

Common stock equivalents, including stock options, warrants and restricted shares totaling 65.7 million shares for the three months ended September 30, 2015 were not included in the computation of diluted earnings per share of common stock because the effect would have been anti-dilutive. Common stock equivalents, including stock options, warrants, restricted shares, convertible debt, and preferred stock totaling 238.8 million shares for the nine months ended September 30, 2015 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 loss. Common stock equivalents totaling 9.9 million and 144.2 million shares for the three and nine months ended September 30, 2014, respectively, were not

included in the computation of diluted earnings per share of common stock because the effect would have been anti-dilutive.

	September 30, 2015		December 31, 2014

	(In thousands)
Accounts receivable:
Oil, natural gas and natural gas liquids revenues	$	69,542	$	104,370
Joint interest accounts		77,991		140,352
Accrued settlements on derivate contracts		37,803		25,929
Affiliated partnership		146		661
Other		5,765		5,247

	$	191,247	$	276,559



Prepaids and other:
Prepaids	$	6,808	$	6,030
Income tax receivable		—		2,991
Other		53		58

	$	6,861	$	9,079



Accounts payable and accrued liabilities:
Trade payables	$	60,980	$	60,512
Accrued oil and natural gas capital costs		101,963		308,604
Revenues and royalties payable		76,933		100,498
Accrued interest expense		46,898		82,942
Accrued employee compensation		10,540		3,171
Accrued lease operating expenses		20,190		29,681
Drilling advances from partners		11,837		21,220
Affiliated partnership		414		762
Other		6,840		360

	$	336,595	$	607,750

The Company's obligations under its Second Lien Notes, Third Lien Notes and senior unsecured notes are fully and unconditionally guaranteed, jointly and severally, by all of the Company's existing 100% owned subsidiaries, other than HK TMS. See Note 4, "Long-term Debt," for information regarding the Company's Senior Credit Agreement, Second Lien Notes, Third Lien Notes and senior unsecured notes. On June 16, 2014, the Company contributed undeveloped acreage in Mississippi and Louisiana that management believes is prospective for the TMS to HK TMS. See Note 9, "Mezzanine Equity," for a discussion of the restrictions on the transfer of assets between the Company and HK TMS.

The following condensed consolidating balance sheets, condensed consolidating statements of operations, and condensed consolidating statements of cash flows for the parent company, subsidiary guarantors on a combined basis, the non-guarantor subsidiary, the consolidating adjustments and the total consolidated amounts are presented as of September 30, 2015 and December 31, 2014 and for the three and nine months ended September 30, 2015 and 2014. Investments in the subsidiaries are accounted for under the equity method. Such condensed consolidating financial information may not necessarily be indicative of the financial position, results of operations or cash flows had these subsidiaries operated as independent entities.

	Three Months Ended September 30, 2015

	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Consolidated
	(In thousands)
Operating revenues:
Oil, natural gas and natural gas liquids sales:
Oil	$	—		$	117,529		$	4,316		$	—		$	121,845
Natural gas		—			5,058			—			—			5,058
Natural gas liquids		—			2,615			—			—			2,615

Total oil, natural gas and natural gas liquids sales		—			125,202			4,316			—			129,518
Other		—			421			—			—			421

Total operating revenues		—			125,623			4,316			—			129,939

Operating expenses:
Production:
Lease operating		—			21,686			562			—			22,248
Workover and other		—			4,773			(4	)		—			4,769
Taxes other than income		—			11,811			291			—			12,102
Gathering and other		—			9,091			—			—			9,091
Restructuring		—			434			—			—			434
General and administrative		13,704			7,314			383			(374	)		21,027
Depletion, depreciation and accretion		496			73,680			5,401			(2,506	)		77,071
Full cost ceiling impairment		—			475,801			33,575			2,506			511,882

Total operating expenses		14,200			604,590			40,208			(374	)		658,624

Income (loss) from operations		(14,200	)		(478,967	)		(35,892	)		374			(528,685	)
Other income (expenses):
Net gain (loss) on derivative contracts		—			204,621			—			—			204,621
Interest expense and other, net		(85,956	)		28,722			(744	)		1			(57,977	)
Gain (loss) on extinguishment of debt		535,141			—			—			—			535,141

Total other income (expenses)		449,185			233,343			(744	)		1			681,785

Income (loss) before income taxes		434,985			(245,624	)		(36,636	)		375			153,100
Income tax benefit (provision)		(6,224	)		6,121			—			(5,922	)		(6,025	)
Equity in earnings of subsidiary, net of tax		(301,037	)		(61,534	)		—			362,571			—

Net income (loss)		127,724			(301,037	)		(36,636	)		357,024			147,075
Series A preferred dividends		(4,196	)		—			—			—			(4,196	)
Preferred dividends and accretion on redeemable noncontrolling interest		—			—			(19,351	)		—			(19,351	)

Net income (loss) available to common stockholders	$	123,528		$	(301,037	)	$	(55,987	)	$	357,024		$	123,528

	Three Months Ended September 30, 2014

	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Consolidated
	(In thousands)
Operating revenues:
Oil, natural gas and natural gas liquids sales:
Oil	$	—		$	282,644		$	5,219		$	—		$	287,863
Natural gas		—			8,248			—			—			8,248
Natural gas liquids		—			10,273			—			—			10,273

Total oil, natural gas and natural gas liquids sales		—			301,165			5,219			—			306,384
Other		—			125			—			—			125

Total operating revenues		—			301,290			5,219			—			306,509

Operating expenses:
Production:
Lease operating		—			27,869			225			—			28,094
Workover and other		—			5,773			—			—			5,773
Taxes other than income		76			28,382			74			—			28,532
Gathering and other		—			7,460			—			—			7,460
General and administrative		18,591			10,621			1,613			(1,256	)		29,569
Depletion, depreciation and accretion		685			132,756			4,161			(2,024	)		135,578
Full cost ceiling impairment		—			—			20,893			(20,893	)		—

Total operating expenses		19,352			212,861			26,966			(24,173	)		235,006

Income (loss) from operations		(19,352	)		88,429			(21,747	)		24,173			71,503
Other income (expenses):
Net gain (loss) on derivative contracts		—			163,287			—			—			163,287
Interest expense and other, net		(79,212	)		40,907			(145	)		—			(38,450	)

Total other income (expenses)		(79,212	)		204,194			(145	)		—			124,837

Income (loss) before income taxes		(98,564	)		292,623			(21,892	)		24,173			196,340
Income tax benefit (provision)		—			1,423			482			(610	)		1,295
Equity in earnings of subsidiary, net of tax		290,376			(3,671	)		—			(286,705	)		—

Net income (loss)		191,812			290,375			(21,410	)		(263,142	)		197,635
Series A preferred dividends		(4,959	)		—			—			—			(4,959	)
Preferred dividends and accretion on redeemable noncontrolling interest		—			—			(5,823	)		—			(5,823	)

Net income (loss) available to common stockholders	$	186,853		$	290,375		$	(27,233	)	$	(263,142	)	$	186,853

	Nine Months Ended September 30, 2015

	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Consolidated
	(In thousands)
Operating revenues:
Oil, natural gas and natural gas liquids sales:
Oil	$	—		$	390,526		$	13,842		$	—		$	404,368
Natural gas		—			17,595			—			—			17,595
Natural gas liquids		—			10,572			—			—			10,572

Total oil, natural gas and natural gas liquids sales		—			418,693			13,842			—			432,535
Other		—			1,622			—			—			1,622

Total operating revenues		—			420,315			13,842			—			434,157

Operating expenses:
Production:
Lease operating		—			79,616			1,650			—			81,266
Workover and other		—			11,614			—			—			11,614
Taxes other than income		—			36,407			839			—			37,246
Gathering and other		—			30,583			—			—			30,583
Restructuring		—			2,664			—			—			2,664
General and administrative		44,056			23,951			1,818			(1,727	)		68,098
Depletion, depreciation and accretion		1,688			285,878			15,171			(5,328	)		297,409
Full cost ceiling impairment		—			1,927,431			81,759			5,328			2,014,518

Total operating expenses		45,744			2,398,144			101,237			(1,727	)		2,543,398

Income (loss) from operations		(45,744	)		(1,977,829	)		(87,395	)		1,727			(2,109,241	)
Other income (expenses):
Net gain (loss) on derivative contracts		—			216,805			—			—			216,805
Interest expense and other, net		(254,716	)		78,288			(3,778	)		—			(180,206	)
Gain (loss) on extinguishment of debt		557,907			—			—			—			557,907
Gain (loss) on extinguishment of Convertible Note and modification of February 2012 Warrants		(8,219	)		—			—			—			(8,219	)

Total other income (expenses)		294,972			295,093			(3,778	)		—			586,287

Income (loss) before income taxes		249,228			(1,682,736	)		(91,173	)		1,727			(1,522,954	)
Income tax benefit (provision)		(6,224	)		—			—			—			(6,224	)
Equity in earnings of subsidiary, net of tax		(1,811,251	)		(128,515	)		—			1,939,766			—

Net income (loss)		(1,568,247	)		(1,811,251	)		(91,173	)		1,941,493			(1,529,178	)
Series A preferred dividends		(13,999	)		—			—			—			(13,999	)
Preferred dividends and accretion on redeemable noncontrolling interest		—			—			(39,069	)		—			(39,069	)

Net income (loss) available to common stockholders	$	(1,582,246	)	$	(1,811,251	)	$	(130,242	)	$	1,941,493		$	(1,582,246	)

	Nine Months Ended September 30, 2014

	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Consolidated
	(In thousands)
Operating revenues:
Oil, natural gas and natural gas liquids sales:
Oil	$	—		$	841,193		$	6,911		$	—		$	848,104
Natural gas		—			27,965			—			—			27,965
Natural gas liquids		—			28,396			—			—			28,396

Total oil, natural gas and natural gas liquids sales		—			897,554			6,911			—			904,465
Other		—			4,337			—			—			4,337

Total operating revenues		—			901,891			6,911			—			908,802

Operating expenses:
Production:
Lease operating		—			95,349			351			—			95,700
Workover and other		—			12,550			—			—			12,550
Taxes other than income		228			82,597			177			—			83,002
Gathering and other		—			18,119			—			—			18,119
Restructuring		—			987			—			—			987
General and administrative		55,850			33,765			3,889			(3,394	)		90,110
Depletion, depreciation and accretion		2,038			383,652			4,883			(1,617	)		388,956
Full cost ceiling impairment		—			61,165			20,893			(20,893	)		61,165
Other operating property and equipment impairment		—			3,789			—			—			3,789

Total operating expenses		58,116			691,973			30,193			(25,904	)		754,378

Income (loss) from operations		(58,116	)		209,918			(23,282	)		25,904			154,424
Other income (expenses):
Net gain (loss) on derivative contracts		—			8,589			—			—			8,589
Interest expense and other, net		(237,307	)		130,331			(138	)		—			(107,114	)

Total other income (expenses)		(237,307	)		138,920			(138	)		—			(98,525	)

Income (loss) before income taxes		(295,423	)		348,838			(23,420	)		25,904			55,899
Income tax benefit (provision)		—			1,295			(80	)		80			1,295
Equity in earnings of subsidiary, net of tax		345,898			(4,236	)		—			(341,662	)		—

Net income (loss)		50,475			345,897			(23,500	)		(315,678	)		57,194
Series A preferred dividends		(14,878	)		—			—			—			(14,878	)
Preferred dividends and accretion on redeemable noncontrolling interest		—			—			(6,719	)		—			(6,719	)

Net income (loss) available to common stockholders	$	35,597		$	345,897		$	(30,219	)	$	(315,678	)	$	35,597

	September 30, 2015

	Parent Company			Guarantor Subsidiaries			Non- Guarantor Subsidiary			Eliminations			Consolidated
	(In thousands)
Current assets:
Cash	$	—		$	109		$	6,145		$	—		$	6,254
Accounts receivable		88			179,974			11,189			(4	)		191,247
Receivables from derivative contracts		—			327,535			—			—			327,535
Restricted cash		—			—			16,541			—			16,541
Inventory		—			3,964			81			—			4,045
Prepaids and other		635			5,983			243			—			6,861

Total current assets		723			517,565			34,199			(4	)		552,483

Oil and natural gas properties (full cost method):
Evaluated		—			6,503,277			284,242			(4,350	)		6,783,169
Unevaluated		—			1,596,756			220,481			—			1,817,237

Gross oil and natural gas properties		—			8,100,033			504,723			(4,350	)		8,600,406
Less—accumulated depletion		—			(5,005,211	)		(256,655	)		4,350			(5,257,516	)

Net oil and natural gas properties		—			3,094,822			248,068			—			3,342,890

Other operating property and equipment:
Gas gathering and other operating assets		12,472			117,433			175			—			130,080
Less—accumulated depreciation		(8,209	)		(12,246	)		(43	)		—			(20,498	)

Net other operating property and equipment		4,263			105,187			132			—			109,582

Other noncurrent assets:
Receivables from derivative contracts		—			73,583			—			—			73,583
Debt issuance costs, net		42,598			—			—			—			42,598
Deferred income taxes		1,794			125,829			—			—			127,623
Intercompany notes and accounts receivable		4,789,961			246,428			—			(5,036,389	)		—
Investment in subsidiary		—			145,637			—			(145,637	)		—
Equity in oil and natural gas partnership		—			4,082			—			—			4,082
Funds in escrow and other		515			1,406			—			—			1,921

Total assets	$	4,839,854		$	4,314,539		$	282,399		$	(5,182,030	)	$	4,254,762



Current liabilities:
Accounts payable and accrued liabilities	$	—		$	364,209		$	6,844		$	(34,458	)	$	336,595
Asset retirement obligations		—			144			—			—			144
Current portion of deferred income taxes		1,794			125,829			—			—			127,623

Total current liabilities		1,794			490,182			6,844			(34,458	)		464,362

Long-term debt		3,111,229			—			—			—			3,111,229
Other noncurrent liabilities:
Liabilities from derivative contracts		—			623			—			—			623
Asset retirement obligations		—			41,075			994			—			42,069
Intercompany notes and accounts payable		246,428			4,789,961			—			(5,036,389	)		—
Investment in subsidiary		1,007,465			—			—			(1,007,465	)		—
Other		—			163			7,143			—			7,306
Commitments and contingencies
Mezzanine equity:
Redeemable noncontrolling interest		—			—			156,235			—			156,235
Stockholders' equity:
Preferred stock		—			—			—			—			—
Common stock		61			—			—			—			61
Additional paid-in capital		3,278,858			—			403,677			(403,677	)		3,278,858
Retained earnings (accumulated deficit)		(2,805,981	)		(1,007,465	)		(292,494	)		1,299,959			(2,805,981	)

Total stockholders' equity		472,938			(1,007,465	)		111,183			896,282			472,938

Total liabilities and stockholders' equity	$	4,839,854		$	4,314,539		$	282,399		$	(5,182,030	)	$	4,254,762

	December 31, 2014

	Parent Company			Guarantor Subsidiaries			Non- Guarantor Subsidiary			Eliminations			Consolidated
	(In thousands)
Current assets:
Cash	$	—		$	15		$	43,698		$	—		$	43,713
Accounts receivable		—			262,543			14,858			(842	)		276,559
Receivables from derivative contracts		—			352,530			—			—			352,530
Restricted cash		—			—			16,131			—			16,131
Inventory		—			4,619			74			—			4,693
Prepaids and other		372			8,707			—			—			9,079

Total current assets		372			628,414			74,761			(842	)		702,705

Oil and natural gas properties (full cost method):
Evaluated		—			6,169,553			225,617			(4,350	)		6,390,820
Unevaluated		—			1,558,412			271,374			—			1,829,786

Gross oil and natural gas properties		—			7,727,965			496,991			(4,350	)		8,220,606
Less—accumulated depletion		—			(2,797,606	)		(159,782	)		4,350			(2,953,038	)

Net oil and natural gas properties		—			4,930,359			337,209			—			5,267,568

Other operating property and equipment:
Gas gathering and other operating assets		14,523			112,103			178			—			126,804
Less—accumulated depreciation		(6,522	)		(8,259	)		(17	)		—			(14,798	)

Net other operating property and equipment		8,001			103,844			161			—			112,006

Other noncurrent assets:
Receivables from derivative contracts		—			151,324			—			—			151,324
Debt issuance costs, net		55,904			—			—			—			55,904
Deferred income taxes		(54	)		136,880			—			—			136,826
Intercompany notes and accounts receivable		4,891,427			239,250			—			(5,130,677	)		—
Investment in subsidiary		803,786			274,553			—			(1,078,339	)		—
Equity in oil and natural gas partnership		—			4,309			—			—			4,309
Funds in escrow and other		515			684			2,634			—			3,833

Total assets	$	5,759,951		$	6,469,617		$	414,765		$	(6,209,858	)	$	6,434,475



Current liabilities:
Accounts payable and accrued liabilities	$	—		$	592,340		$	50,706		$	(35,296	)	$	607,750
Asset retirement obligations		—			106			—			—			106
Current portion of deferred income taxes		1,794			135,032			—			—			136,826

Total current liabilities		1,794			727,478			50,706			(35,296	)		744,682

Long-term debt		3,746,736			—			—			—			3,746,736
Other noncurrent liabilities:
Liabilities from derivative contracts		—			9,387			—			—			9,387
Asset retirement obligations		—			37,538			833			—			38,371
Intercompany notes and accounts payable		239,250			4,891,427			—			(5,130,677	)		—
Other		2			1			5,961			—			5,964
Commitments and contingencies
Mezzanine equity:
Redeemable noncontrolling interest		—			—			117,166			—			117,166
Stockholders' equity:
Preferred stock		—			—			—			—			—
Common stock		42			—			—			—			42
Additional paid-in capital		2,995,402			—			402,351			(402,351	)		2,995,402
Retained earnings (accumulated deficit)		(1,223,275	)		803,786			(162,252	)		(641,534	)		(1,223,275	)

Total stockholders' equity		1,772,169			803,786			240,099			(1,043,885	)		1,772,169

Total liabilities and stockholders' equity	$	5,759,951		$	6,469,617		$	414,765		$	(6,209,858	)	$	6,434,475

	Nine Months Ended September 30, 2015

	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Consolidated
	(In thousands)
Cash flows from operating activities:
Net cash provided by (used in) operating activities	$	(289,053	)	$	615,736		$	5,511		$	—			332,194
Cash flows from investing activities:
Oil and natural gas capital expenditures		—			(489,084	)		(42,657	)		—			(531,741	)
Proceeds received from sale of oil and natural gas assets		—			1,111			—			—			1,111
Other operating property and equipment capital expenditures		(772	)		(9,144	)		3			—			(9,913	)
Advances to subsidiary		120,402			—			—			(120,402	)		—
Funds held in escrow and other		—			1,877			—			—			1,877

Net cash provided by (used in) investing activities		119,630			(495,240	)		(42,654	)		(120,402	)		(538,666	)

Cash flows from financing activities:
Proceeds from borrowings		1,579,000			—			—			—			1,579,000
Repayments of borrowings		(1,392,000	)		—			—			—			(1,392,000	)
Debt issuance costs		(25,703	)		—			—			—			(25,703	)
Series A preferred dividends		(4,656	)		—			—			—			(4,656	)
Common stock issued		15,354			—			—			—			15,354
Restricted cash		—			—			(410	)		—			(410	)
Proceeds from subsidiary		—			(120,402	)		—			120,402			—
Offering costs and other		(2,572	)		—			—			—			(2,572	)

Net cash provided by (used in) financing activities		169,423			(120,402	)		(410	)		120,402			169,013

Net increase (decrease) in cash		—			94			(37,553	)		—			(37,459	)
Cash at beginning of period		—			15			43,698			—			43,713

Cash at end of period	$	—		$	109		$	6,145		$	—		$	6,254

	Nine Months Ended September 30, 2014

	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Consolidated
	(In thousands)
Cash flows from operating activities:
Net cash provided by (used in) operating activities	$	(277,458	)	$	859,079		$	3,057		$	(2,788	)	$	581,890
Cash flows from investing activities:
Oil and natural gas capital expenditures		—			(1,116,504	)		(64,933	)		2,788			(1,178,649	)
Proceeds received from sale of oil and natural gas assets		—			446,197			33,777			—			479,974
Advance on carried interest		—			(62,500	)		(126,942	)		—			(189,442	)
Other operating property and equipment capital expenditures		(1,050	)		(39,259	)		(47	)		—			(40,356	)
Advances to subsidiary		(63,183	)		(154,138	)		—			217,321			—
Funds held in escrow and other		—			1,221			—			—			1,221

Net cash provided by (used in) investing activities		(64,233	)		(924,983	)		(158,145	)		220,109			(927,252	)

Cash flows from financing activities:
Proceeds from borrowings		1,744,000			—			—			—			1,744,000
Repayments of borrowings		(1,399,000	)		—			—			—			(1,399,000	)
Debt issuance costs		(757	)		—			—			—			(757	)
HK TMS, LLC preferred stock issued		—			—			110,051			—			110,051
HK TMS, LLC tranche rights		—			—			4,516			—			4,516
Preferred dividends on redeemable noncontrolling interest		—			—			(3,518	)		—			(3,518	)
Restricted cash		—			—			(15,984	)		—			(15,984	)
Proceeds from subsidiary		—			63,183			154,138			(217,321	)		—
Offering costs and other		(2,553	)		—			461			—			(2,092	)

Net cash provided by (used in) financing activities		341,690			63,183			249,664			(217,321	)		437,216

Net increase (decrease) in cash		(1	)		(2,721	)		94,576			—			91,854
Cash at beginning of period		1			2,833			—			—			2,834

Cash at end of period	$	—		$	112		$	94,576		$	—		$	94,688

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, 2015 and 2014 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, 2014.

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. We were incorporated in Delaware on February 5, 2004 and were recapitalized on February 8, 2012. During 2012, we focused our efforts on the acquisition of unevaluated leasehold and producing properties in selected prospect areas, providing us with an extensive drilling inventory in multiple basins that we believe allow for multiple years of production growth and broad flexibility to direct our capital resources to projects with the greatest potential returns. In the years since, we focused on the development of acquired properties and also divested non-core assets in order to fund activities in our core resource plays.

Our oil and natural gas assets consist of developed and undeveloped acreage positions in unconventional liquids-rich basins/fields. We have acquired acreage and may acquire additional acreage in the Bakken/Three Forks formations in North Dakota and the Eagle Ford formation in East Texas, as well as other areas.

Our average daily oil and natural gas production increased slightly in the first nine months of 2015 compared to the same period in the prior year. During the first nine months of 2015, production averaged 41,696 barrels of oil equivalent (Boe) per day (Boe/d) compared to average daily production of 40,769 Boe/d during the first nine months of 2014. The increase in production compared to the prior year period was driven primarily by operated drilling results and increased production volumes associated with the development of properties in the Bakken/Three Forks and the Eagle Ford formation in East Texas (which we refer to as "El Halcón"). These areas collectively accounted for an increase of approximately 2,400 Boe/d. This increase was partially offset by production decreases from our divestiture of non-core properties during 2014. During the first nine months of 2015, we participated in the drilling of 160 gross (38.1 net) wells, all of which were completed and capable of production. During the three months ended September 30, 2015, production averaged 40,739 Boe/d and we spent $124.0 million on oil and natural gas capital expenditures, of which $87.3 million related to drilling and completion costs.

Oil and natural gas prices are inherently volatile and decreased considerably over the latter half of 2014 and have remained low in 2015. In response to this we have significantly curtailed our capital spending, reduced operating costs, and have incurred substantial asset impairments, primarily as a result of the full cost ceiling test calculation. Sustained lower commodity prices will continue to have a material impact upon our full cost ceiling test calculation. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

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. If the average of the oil and natural gas prices for the first day of each month for the trailing 12-month period ended September 30, 2015 had been $50.37 per barrel for oil and $2.66 per million British thermal units for natural gas, holding all other factors constant, our ceiling test limitation related to the net book value of our proved oil and natural gas properties would have been reduced by an additional $527.4 million. The foregoing prices were calculated using a simple average of the oil and natural gas prices on the first day of the month for each of the 10 months ended October 2015, with the crude oil price for October 2015 of $44.74 per barrel held constant for the remaining two months to create a trailing 12-month period. As a consequence of the reduction in the ceiling test limitation, our ceiling test impairment would have increased by an additional $527.4 million, partly as a result of a decrease in our proved undeveloped reserves of approximately 39%, primarily due to certain locations that would not be economical when using these prices. The foregoing calculation of the impact of lower commodity prices was prepared assuming that all inputs and factors other than oil and natural gas prices remain constant, thereby isolating the impact of commodity prices on our ceiling test limitation and proved reserves. Price is only one variable in the estimation of our proved reserves, and other factors could have a significant impact on future reserves and the present value of future cash flows, including, but not limited to, extensions and discoveries, changes in costs, drilling results, well performance and changes in our development plans. There are numerous uncertainties inherent in the estimation of proved reserves and accounting for oil and natural gas properties in subsequent periods and this estimate should not be construed as indicative of our development plans or future results.

On September 10, 2015, in conjunction with the issuance of the Third Lien Notes (defined below), we entered into the Eleventh Amendment to our Senior Credit Agreement (the Eleventh Amendment) which, among other things, permitted us to incur the debt under the Third Lien Notes and to grant the liens in connection therewith; excluded the Third Lien Notes for the calculation of the total secured debt to EBITDA ratio; and reduced the borrowing base under our Senior Credit Agreement to $850.0 million. On October 29, 2015, our borrowing base under the Senior Credit Agreement was reaffirmed at $850.0 million with the next redetermination scheduled for spring of 2016.

On May 1, 2015, in conjunction with the issuance of the Second Lien Notes (defined below), we entered into the Tenth Amendment to our Senior Credit Agreement (the Tenth Amendment) which among other things, permitted us to incur the debt under the Second Lien Notes and to grant the liens in connection therewith; replaced the interest coverage ratio covenant that had been modified in the Ninth Amendment with a covenant that requires the ratio of our total secured debt (excluding the Third Lien Notes pursuant the Eleventh Amendment) to EBITDA be no greater than 2.75 to 1.00; reduced the borrowing base; and extended the maturity date of the Senior Credit Agreement to August 1, 2019. Prior to the Tenth Amendment, under the Ninth Amendment executed on February 25, 2015, the Senior Credit Agreement had a required minimum coverage of interest expenses of not less than 2.0 to 1.0 through March 31, 2016 and not less than 2.5 to 1.0 for subsequent periods.

On September 10, 2015, we issued approximately $1.02 billion aggregate principal amount of new 13.0% third lien senior secured notes due 2022 (the Third Lien Notes) in exchange for approximately $497.2 million principal amount of our 9.75% senior notes due 2020, $774.7 million principal amount of our 8.875% senior notes due 2021, and $294.4 million principal amount of our 9.25% senior notes due 2022 in privately negotiated transactions with certain holders of our outstanding senior unsecured notes. The Company recorded the issuance of the Third Lien Notes at par value and also recognized a

$535.1 million net gain on the extinguishment of debt, as a $548.2 million gain on the exchange was partially offset by the writedown of $13.1 million associated with related issuance costs and discounts and premiums for the respective unsecured notes. The net gain is recorded in "Gain (loss) on extinguishment of debt" in the unaudited condensed consolidated statements of operations. At closing, we paid all accrued and unpaid interest since the respective interest payment dates of the notes surrendered in the exchange. Interest on the Third Lien Notes accrues at a rate of 13.0% per annum, payable semi-annually on February 15 and August 15, commencing on February 15, 2016. The Third Lien Notes mature on February 15, 2022. The Third Lien Notes are secured by third-priority liens on the same collateral securing our Senior Credit Agreement and Second Lien Notes. The Third Lien Notes are governed by an Indenture dated September 10, 2015, which contains affirmative and negative covenants substantially similar to those governing our outstanding Second Lien Notes. The Third Lien Notes are fully and unconditionally guaranteed on a senior basis by our subsidiary guarantors' assets and by certain future subsidiaries of ours.

On June 1, 2015, our subsidiary, HK TMS, LLC (HK TMS), and funds and accounts managed by affiliates of Apollo Global Management, LLC (Apollo) entered into an amendment to their original agreement (the HK TMS Amendment) which, among other things, i) commits HK TMS to drill a minimum of 6.5 net wells in each of the five consecutive twelve month periods beginning December 31, 2015 and ii) allows for the redemption of preferred shares at the greater of a 12% annual rate of return plus principal and 1.25 times Apollo's investment plus applicable fees (the Redemption Price), between March 1, 2016 and June 30, 2016 at the election of Apollo to the extent there is available cash above the minimum cash balance. For any commitment period in which HK TMS does not meet its drilling obligation, HK TMS must use available cash, above its minimum required cash balance, to redeem preferred shares at the Redemption Price.

On March 9, 2015, we entered into an amendment (the HALRES Note Amendment) to our convertible note in the principal amount of $289.7 million due 2017 (the Convertible Note). The HALRES Note Amendment extends the maturity date of the Convertible Note by three years, from February 8, 2017 to February 8, 2020. The Convertible Note originally provided for prepayment without premium or penalty at any time after February 8, 2014, at which time it also became convertible into shares of the Company's common stock at a conversion price of $4.50 per share. These dates have been extended and the conversion price has been adjusted, such that at any time after March 9, 2017, we may prepay the Convertible Note without premium or penalty, and HALRES may elect to convert all or any portion of unpaid principal and interest outstanding under the Convertible Note to shares of our common stock at a conversion price of $2.44 per share, subject to adjustments for stock splits and other customary anti-dilution provisions as set forth in the Convertible Note. At the same time, we also entered into an amendment (the Warrant Amendment, and collectively with the HALRES Note Amendment, the Amendments) to our five year warrants (the February 2012 Warrants) which extends the term of the February 2012 Warrants from February 8, 2017 to February 8, 2020 and adjusts the exercise price of the February 2012 Warrants from $4.50 to $2.44 per share. The Amendments were approved by our stockholders on May 6, 2015, in accordance with the rules of the New York Stock Exchange.

On May 1, 2015, we completed the issuance of $700 million aggregate principal amount of 8.625% senior secured notes due 2020 (the Second Lien Notes) in a private offering. The Second Lien Notes were issued at par. The net proceeds from the sale of the Second Lien Notes were approximately

$686.2 million (after deducting offering fees and expenses). We used the net proceeds from the offering to repay a majority of the then outstanding borrowings under our Senior Credit Agreement. Interest on the Second Lien Notes is payable on February 1 and August 1 of each year, beginning on August 1, 2015. The Second Lien Notes will mature on February 1, 2020. The Second Lien Notes are secured by second-priority liens on substantially all of our and our subsidiary guarantors' assets that secure our Senior Credit Agreement.

During the second quarter of 2015, we entered into several exchange agreements with holders of our senior unsecured notes in which they agreed to exchange an aggregate $258.0 million principal amount of their senior unsecured notes for approximately 144.8 million shares of our common stock.

On May 7, 2015, we entered into an exchange agreement with Union Square Park Partners, L.P., a holder of our 2022 Notes and 2021 Notes, pursuant to which it agreed to exchange approximately $5.8 million principal amount of such notes for approximately 3.5 million shares of our common stock, resulting in an effective exchange price of $1.70 per share. Of the aggregate $5.8 million principal amount of senior notes exchanged by the holder, approximately $2.0 million is principal amount of 2022 Notes and approximately $3.8 million is principal amount of 2021 Notes. The exchange closed on May 15, 2015, at which time we also paid all accrued and unpaid interest on the notes since the prior interest payment dates for each of the 2022 Notes and 2021 Notes.

On April 24, 2015, we entered into an exchange agreement with several investment funds advised by Pioneer Investments, each of which is a holder of our 2020 Notes, 2021 Notes and 2022 Notes (the Senior Notes), pursuant to which the funds agreed to exchange an aggregate $25.0 million principal amount of the Senior Notes for approximately 14.8 million shares of our common stock, resulting in an effective exchange price of $1.69 per share. Of the aggregate $25.0 million principal amount of Senior Notes exchanged by the holders, approximately $2.8 million is principal amount of 2020 Notes, approximately $16.8 million is principal amount of 2021 Notes and approximately $5.4 million is principal amount of 2022 Notes. The exchanges closed on various dates from April 30, 2015 through May 4, 2015, at which time we also paid all accrued and unpaid interest since the prior interest payment dates for each of the Senior Notes.

On April 22, 2015, we entered into an exchange agreement with J.P. Morgan Securities LLC, a holder of our 2021 Notes, pursuant to which it agreed to exchange approximately $40.0 million principal amount of such notes for approximately 22.2 million shares of our common stock, resulting in an effective exchange price of $1.80 per share. The exchange closed on April 29, 2015, at which time we also paid all accrued and unpaid interest on the notes since the prior interest payment date in November 2014.

On April 15, 2015, we entered into an exchange agreement with Goldman Sachs Asset Management, L.P., on behalf of certain of its funds and accounts which hold our 2020 Notes, pursuant to which the holders agreed to exchange approximately $70.7 million principal amount of such notes for approximately 38.8 million shares of our common stock, resulting in an effective exchange price of $1.82 per share. The exchanges closed on various dates from April 22, 2015 through April 28, 2015, at which time we also paid all accrued and unpaid interest on the notes since the prior interest payment date in January 2015.

On April 7, 2015, we entered into an exchange agreement with two investment funds advised by Franklin Templeton Investments, each of which is an existing holder of our 2020 Notes, pursuant to which the funds agreed to exchange an aggregate $116.5 million principal amount of such notes for approximately 65.5 million shares of our common stock, resulting in an effective exchange price of $1.78 per share. The exchange closed on April 13, 2015, at which time we also paid all accrued and unpaid interest on the notes since the prior interest payment date in January 2015.

On March 18, 2015, we entered into an Equity Distribution Agreement (the Equity Distribution Agreement) with BMO Capital Markets Corp., Jefferies LLC and MLV & Co. LLC (collectively, the Managers). Pursuant to the terms of the Equity Distribution Agreement, we may sell, from time to time through the Managers, shares of our common stock having an aggregate offering price of up to $150 million (the Shares). Sales of the Shares, if any, will be made by means of ordinary brokers' transactions through the facilities of the New York Stock Exchange at market prices, or as otherwise agreed by us and the Managers. For the nine months ended September 30, 2015, we sold approximately 9.4 million shares for net proceeds of approximately $15.1 million, after deducting offering expenses.

Our near-term capital spending requirements are expected to be funded with cash flows from operations. In addition, we have the ability to draw on our Senior Credit Agreement, which has a current borrowing base of $850.0 million. Our borrowing base is redetermined on a semi-annual basis (with us and the lenders each having the right to one interim unscheduled redetermination between any two consecutive semi-annual redeterminations) and adjusted based on the estimated value of our oil and natural gas reserves, the amount and cost of our other indebtedness and other relevant factors. On October 29, 2015, our borrowing base under the Senior Credit Agreement was reaffirmed at $850.0 million with the next redetermination scheduled for spring of 2016. Our ability to utilize the full amount of our borrowing capacity is influenced by a variety of factors, including redeterminations of our borrowing base and covenants under our Senior Credit Agreement and our senior debt indentures. Our Senior Credit Agreement contains customary financial and other covenants, including minimum working capital levels (the ratio of current assets plus the unused commitment under the Senior Credit Agreement to current liabilities) of not less than 1.0 to 1.0 and a covenant that requires the ratio of our total secured debt to EBITDA be no greater than 2.75 to 1.0. Pursuant to the Eleventh Amendment, the Third Lien Notes are excluded from the calculation of total secured debt to EBITDA ratio. We are also subject to additional covenants limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt, changes of control, asset sales, and liens on properties. Additionally, the indentures governing our senior debt contain covenants limiting our ability to incur additional indebtedness, including borrowings under our Senior Credit Agreement, unless we meet one of two alternative tests. The first test, the fixed charge coverage ratio test, applies to all indebtedness and requires that after giving effect to the incurrence of additional debt the ratio of our adjusted consolidated EBITDA (as defined in our indentures) to our adjusted consolidated interest expense over the trailing four fiscal quarters will be at least 2.0 to 1.0. The second test allows us to incur additional indebtedness, beyond the limitations of the fixed charge coverage ratio test, as long as this additional debt is incurred under Credit Facilities (as defined in our indentures) and, in the case of certain secured indebtedness, the amount thereof is not more than, subject to certain exceptions, the greater of (i) $950 million, (ii) the borrowing base in effect under our Senior Credit Agreement, and (iii) 30% of our adjusted consolidated net tangible assets, or ACNTA, and, in the case of unsecured indebtedness, the amount thereof is not more than the greater of the fixed sum of $750 million or 30% of our ACNTA. ACNTA is defined in all of our indentures and is determined primarily by the value of discounted future net revenues from proved oil and natural gas reserves plus the capitalized cost attributable to our unevaluated properties. At September 30, 2015, under the effective borrowing base of $850.0 million, we had $44.0 million of indebtedness outstanding under our Senior Credit Agreement, $1.6 million of letters of credit outstanding and approximately $804.4 million of borrowing capacity available. At September 30, 2015, we were in compliance with the financial covenants under the Senior Credit Agreement.

Our ability to meet our debt covenants and our capacity to incur additional indebtedness will depend on our future performance, which will be affected by financial, business, economic, regulatory

and other factors. For example, lower oil and natural gas prices could result in a redetermination of the borrowing base under our Senior Credit Agreement at a lower level and reduce our adjusted consolidated EBITDA, as well as our ACNTA, and thus could reduce our ability to incur indebtedness. Our strategic divestitures of non-core producing properties in favor of investing in undeveloped acreage, coupled with our current drilling plans have also impacted our near-term ability to comply with certain debt covenants by reducing our production and reserves on a current and, for purposes of covenant calculations, a pro forma historical basis, as drilling takes time to replace these losses. Of course, over the longer term, we expect that our strategy and our investments will result in increased production and reserves, lower lease operating costs and more abundant drilling opportunities. As a consequence, we constantly monitor our liquidity and capital resources, endeavor to anticipate potential covenant compliance issues and work with the lenders under our Senior Credit Agreement to address any such issues ahead of time.

We have obtained amendments to the covenants under our Senior Credit Agreement under circumstances where we anticipated that it might be challenging for us to comply with our financial covenants for a particular period of time. During 2013, we obtained amendments to the calculation of the interest coverage ratio covenant under our Senior Credit Agreement allowing us to annualize our quarterly EBITDA because, among other things, we anticipated that our strategic decision to divest various non-core producing properties and invest in the acquisition and drilling of undeveloped acreage would have caused us to fall below the interest coverage ratio. We requested a reduction in the minimum required interest coverage ratio of 2.0 to 1.0 for 2014 and 2015 and those requests were granted on March 21, 2014 and again on February 25, 2015, respectively. With the Tenth Amendment and the issuance of the Second Lien Notes, the interest coverage ratio was replaced with a total secured debt to EBITDA ratio and with the Eleventh Amendment, in the calculation of total secured debt to EBITDA ratio the Third Lien Notes are excluded. The basis for recent amendment and waiver requests is similar to those described above, i.e., the potential for us to fall out of compliance primarily as a result of our strategic decision to divest producing properties, invest extensively in undeveloped acreage and the long lead times associated with replacing lost production through our drilling program and, in the case of the Eleventh Amendment, due to our desire to reduce overall debt through the exchange of Third Lien Notes for unsecured notes. Declining commodity prices have also adversely impacted our ability to comply with these covenants. As part of our plan to manage liquidity risks, we have scaled back our capital expenditures budget, focused our drilling program on our highest return projects, and we continue to explore opportunities to divest non-core properties.

If, in the future, the lenders under our Senior Credit Agreement are unwilling to provide us with the covenant flexibility we seek, and we are unable to comply with those covenants, we may be forced to repay or refinance amounts then outstanding under the Senior Credit Agreement and seek alternative sources of capital to fund our business and anticipated capital expenditures. In the event that we are unable to access sufficient capital to fund our business and planned capital expenditures, we may be required to curtail our drilling, development, land acquisition and other activities, which could result in a decrease in our production of oil and natural gas, may be subject to forfeitures of leasehold interests to the extent we are unable or unwilling to renew them, and may be forced to sell some of our assets on an untimely or unfavorable basis, each of which could adversely affect our results of operations and financial condition. Further, the failure to comply with the restrictive covenants relating to our indebtedness could result in the declaration of a default and cross default under the instruments governing our indebtedness, potentially resulting in acceleration of our obligations and adversely impacting our financial condition.

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 the capital markets 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 success.

We strive to maintain financial flexibility while pursuing our drilling plans and evaluating potential acquisitions, and will therefore likely continue to access capital markets (if available on acceptable terms) as necessary to, among other things, maintain substantial borrowing capacity under our Senior Credit Agreement, facilitate drilling on our large undeveloped acreage position and permit us to selectively expand our acreage position and infrastructure projects while sustaining sufficient operating cash levels. Our ability to complete future debt and equity offerings and maintain or increase our borrowing base is subject to a number of variables, including our level of oil and natural gas production, reserves and commodity prices, 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 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.

We are exposed to various risks, including energy commodity price risk. When oil, natural gas, and natural gas liquids prices decline significantly, as they did in the latter half of 2014 and throughout 2015, 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 future declines in oil and natural gas 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, swaps, and deferred put options. The total volumes which we hedge through the use of our derivative instruments varies from period to period, however, generally our objective is to hedge approximately 70% to 80% of our current and anticipated production for the next 18 to 24 months. Our hedge policies and objectives may change significantly as our operational profile changes and/or commodities prices change. We do not enter into derivatives contracts for speculative trading purposes.

Our primary sources of cash for the nine months ended September 30, 2015 and 2014 were from operating and financing activities. In the first nine months of 2015, cash generated by operating and financing activities was used to fund our drilling and completion program. See "Results of Operations" for a review of the impact of prices and volumes on sales.

Operating Activities. Net cash provided by operating activities for the nine months ended September 30, 2015 and 2014, was $332.2 million and $581.9 million, respectively. Key drivers of net operating cash flows are commodity prices, production volumes, lower operating costs and realized settlements on our derivative contracts.

The $332.2 million of operating cash flows for the nine months ended September 30, 2015 primarily reflect the impact of realized settlements on our derivative contracts, which largely mitigated the decrease in revenues due to lower commodity prices, as compared to the prior year period. Cash operating expenses also decreased over the prior year period.

The $581.9 million of operating cash flows for the nine months ended September 30, 2014 primarily reflect the impact of increased production from our developmental drilling activities which drove an increase in revenues, as compared to the prior year period, and outpaced related operating expenses. Increased revenues were driven by the increase in production volumes from our Bakken/Three Forks and El Halcón areas.

Investing Activities. The primary driver of cash used in investing activities is capital spending, specifically drilling and completions and, to a lesser extent, the acquisition of unevaluated leasehold acreage in our target areas. Net cash used in investing activities was approximately $538.7 million and $927.3 million for the nine months ended September 30, 2015 and 2014, respectively.

During the first nine months of 2015, we spent $531.7 million on oil and natural gas capital expenditures, of which $418.7 million related to drilling and completion costs and the remainder was primarily associated with capitalized interest, leasing and seismic data. We have significantly decreased our planned capital spending for 2015, as compared to capital expenditure levels in prior years, in response to the significant decrease in crude oil prices over the latter half of 2014 and throughout 2015, and due to the expectation that prices may not recover in the near term. Cash paid for drilling and completion costs during the first nine months of 2015 were attributable to both costs incurred before we slowed our drilling and completion program and costs related to wells spud or drilled during the period.

During the first nine months of 2014, we incurred cash expenditures of $1.2 billion on oil and natural gas capital expenditures, of which $906.5 million related to drilling and completion costs and the remainder was primarily associated with leasing, acquisitions and seismic data. These expenditures were offset by $480.0 million in proceeds received from the divestitures of various non-core assets, including non-core assets in East Texas. As part of the transaction with Apollo, discussed in Item 1. Condensed Consolidated Financial Statements (Unaudited)—Note 9, "Mezzanine Equity," we received proceeds of approximately $33.8 million from the conveyance of an overriding royalty interest to Apollo.

On December 20, 2013, we entered into a carry and earning agreement, as amended (the Agreement) with an independent third party (Seller) associated with the acquisition of certain properties believed to be prospective for the Tuscaloosa Marine Shale (TMS), primarily in Wilkinson County, Mississippi and in West Feliciana and East Feliciana Parishes, Louisiana. The agreement required us to fund up to $189.4 million (the Carry Amount) in exchange for approximately 117,870 net acres. We paid $62.5 million of the Carry Amount at closing on February 28, 2014 and the remaining $126.9 million during the three months ended June 30, 2014, reflected as "Advance on carried interest" in the accompanying unaudited condensed consolidating statements of cash flows. The Carry Amount is to be used by the Seller to fund wells prospective for the TMS to be drilled by the Seller (the Carry Wells) on the Seller's retained acreage. As part of the transaction, we will also receive a 5% working interest in the Carry Wells. As of December 31, 2014, approximately $71.9 million of the Carry Amount remained in escrow to be spent by the Seller and as of September 30, 2015, the Carry Amount was fully expended.

During the nine months ended September 30, 2014, we spent an additional $40.4 million on other operating property and equipment capital expenditures, of which $29.6 million pertained to pipelines and related infrastructure projects, and a majority of the remainder was spent on leasehold improvements.

Financing Activities. Net cash flows provided by financing activities were $169.0 million and $437.2 million for the nine months ended September 30, 2015 and 2014, respectively. The primary drivers of cash provided by financing activities for the nine months ended September 30, 2015 were proceeds received from the issuance of our Second Lien Notes and net borrowings on our Senior Credit Agreement.

On May 1, 2015, we completed the issuance of $700.0 million aggregate principal amount of our Second Lien Notes. The net proceeds to us from the offering were approximately $686.2 million after deducting commissions and offering expenses and were used to repay a majority of the then outstanding borrowings under our Senior Credit Agreement.

During the first nine months of 2015, cash flows from financing activities were modestly impacted by sales of our common stock under the Equity Distribution Agreement. For the nine months ended September 30, 2015, we sold approximately 9.4 million shares for net proceeds of approximately $15.1 million, after deducting offering expenses.

The primary driver of cash provided by financing activities for the nine months ended September 30, 2014 was net borrowings on our Senior Credit Agreement. In addition, on June 16, 2014, we entered into a transaction with Apollo by selling 150,000 preferred interests in HK TMS, which holds all of our acreage in Mississippi and Louisiana believed to be prospective for the TMS. Apollo contributed $150 million to HK TMS and we contributed all our assets related to the TMS as well as $50 million in cash. The proceeds from Apollo were allocated to the components of the transaction, resulting in approximately $110.1 million of proceeds associated with the issuance of HK TMS preferred stock and approximately $4.5 million associated with Apollo's rights to additional preferred shares within cash flows from financing activities and the aforementioned $33.8 million investing cash flows related to the overriding royalty conveyance. The proceeds are to be used to develop the TMS.

We lease corporate office space in Houston, Texas; and Denver, Colorado as well as a number of other field office locations. Rent expense was approximately $6.4 million and $6.0 million for the nine months ended September 30, 2015 and 2014, respectively. As of September 30, 2015, the amount of commitments under office and equipment lease agreements is consistent with the levels at December 31, 2014 disclosed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2014, approximating $53.2 million in the aggregate, and containing various expiration dates through 2024.

In addition, we have commitments for certain equipment under long-term operating lease agreements, namely drilling rigs as well as pipeline and well equipment, with various expiration dates through 2018. During the first quarter of 2015, we terminated a drilling rig contract early in response to the recent decline in crude oil prices, and as such, incurred an early termination fee of $6.0 million, paid over the first half of 2015. If certain requirements are not met by two separate trigger dates, the first being January 1, 2017 and the second being January 12, 2020, we may incur up to an additional $3.0 million in connection with this drilling rig contract. In addition, we have a new drilling rig commitment that began on May 1, 2015, for which we are currently incurring a stacking fee of $17,000 per day. The contract term for this drilling rig commitment extends through the second quarter of 2018. Early termination of our other drilling rig commitments would result in termination penalties approximating $34.3 million, which would be in lieu of the remaining $50.9 million of drilling rig commitments as of September 30, 2015.

We have entered into various long-term gathering, transportation and sales contracts with respect to production from the Bakken/Three Forks formations in North Dakota. As of September 30, 2015, we had in place ten long-term crude oil contracts and six long-term natural gas contracts in this area.

Under the terms of these contracts, we have committed a substantial portion of our Bakken/Three Forks production for periods ranging from one to ten years from the date of first production. The sales prices under these contracts are based on posted market rates. Historically, we have been able to meet our delivery commitments.

On December 20, 2013, we entered into a carry and earning agreement with a Seller, associated with the acquisition of certain properties believed to be prospective for the TMS, primarily in Wilkinson County, Mississippi and in West Feliciana and East Feliciana Parishes, Louisiana. The agreement required us to fund up to $189.4 million in exchange for approximately 117,870 net acres. We paid $62.5 million of the Carry Amount at closing on February 28, 2014 and the remaining $126.9 million during the three months ended June 30, 2014, reflected as "Advance on carried interest" in the accompanying unaudited condensed consolidating statements of cash flows. The Carry Amount is to be used by the Seller to fund wells prospective for the TMS to be drilled by the Seller (the Carry Wells) on the Seller's retained acreage. As part of the transaction, we will also receive a 5% working interest in the Carry Wells. As of December 31, 2014, approximately $71.9 million of the Carry Amount remained in escrow to be spent by the Seller and as of September 30, 2015, the Carry Amount was fully expended.

On June 16, 2014, we entered into a transaction to develop our TMS assets with funds and accounts managed by affiliates of Apollo Global Management, LLC. See Item 1. Condensed Consolidated Financial Statements (Unaudited)—Note 9, "Mezzanine Equity," for a discussion of the drilling obligation associated with the transaction.

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, 2014.

We reported net income of $147.1 million and $197.6 million for the three months ended September 30, 2015 and 2014, respectively. The following table summarizes key items of comparison and their related change for the periods indicated.

	Three Months Ended September 30,

In thousands (except per unit and per Boe amounts)	2015			2014			Change
Net income (loss)	$	147,075		$	197,635		$	(50,560	)
Operating revenues:
Oil		121,845			287,863			(166,018	)
Natural gas		5,058			8,248			(3,190	)
Natural gas liquids		2,615			10,273			(7,658	)
Other		421			125			296
Operating expenses:
Production:
Lease operating		22,248			28,094			(5,846	)
Workover and other		4,769			5,773			(1,004	)
Taxes other than income		12,102			28,532			(16,430	)
Gathering and other		9,091			7,460			1,631
Restructuring		434			—			434
General and administrative:
General and administrative		17,992			24,978			(6,986	)
Share-based compensation		3,035			4,591			(1,556	)
Depletion, depreciation and accretion:
Depletion—Full cost		74,651			132,968			(58,317	)
Depreciation—Other		1,967			2,183			(216	)
Accretion expense		453			427			26
Full cost ceiling impairment		511,882			—			511,882
Other income (expenses):
Net gain (loss) on derivative contracts		204,621			163,287			41,334
Interest expense and other, net		(57,977	)		(38,450	)		(19,527	)
Gain (loss) on extinguishment of debt		535,141			—			535,141
Income tax (provision) benefit		(6,025	)		1,295			(7,320	)
Production:
Oil—MBbls		2,993			3,301			(308	)
Natural Gas—Mmcf		2,300			2,398			(98	)
Natural gas liquids—MBbls		371			306			65
Total MBoe⁽¹⁾		3,748			4,007			(259	)
Average daily production—Boe⁽¹⁾		40,739			43,554			(2,815	)
Average price per unit⁽²⁾:
Oil price—Bbl	$	40.71		$	87.20		$	(46.49	)
Natural gas price—Mcf		2.20			3.44			(1.24	)
Natural gas liquids price—Bbl		7.05			33.57			(26.52	)
Total per Boe⁽¹⁾		34.56			76.46			(41.90	)
Average cost per Boe:
Production:
Lease operating	$	5.94		$	7.01		$	(1.07	)
Workover and other		1.27			1.44			(0.17	)
Taxes other than income		3.23			7.12			(3.89	)
Gathering and other		2.43			1.86			0.57
Restructuring		0.12			—			0.12
General and administrative:
General and administrative		4.80			6.23			(1.43	)
Share-based compensation		0.81			1.15			(0.34	)
Depletion		19.92			33.18			(13.26	)

For the three months ended September 30, 2015, oil, natural gas and natural gas liquids revenues decreased $176.9 million as compared to the same period in 2014 primarily due to lower average realized prices. Average realized prices (excluding the effects of hedging arrangements) decreased from $76.46 per Boe to $34.56 per Boe, representing a 55% decrease from the prior year period. Oil and natural gas prices are inherently volatile and decreased significantly over the latter half of 2014 and throughout 2015. Sustained lower commodity prices will continue to impact our oil, natural gas and natural gas liquids revenues. Average daily production also slightly decreased from the prior year period.

Lease operating expenses decreased $5.8 million for the three months ended September 30, 2015 due to our divestiture of non-core properties in 2014 which, historically, had higher operating costs, as well as our efforts to reduce costs and become a more efficient operator. Lease operating expenses were $5.94 per Boe for the three months ended September 30, 2015, compared to $7.01 per Boe for the same period in 2014. The decrease in lease operating expenses per Boe primarily results from our efforts to reduce costs in our core operating areas.

Taxes other than income decreased $16.4 million for the three months ended September 30, 2015 as compared to the same period in 2014 primarily due to lower oil, natural gas and natural gas liquids revenues attributable to significantly lower commodity prices. 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 $3.23 per Boe and $7.12 per Boe for the three months ended September 30, 2015 and 2014, respectively.

Gathering and other expenses for the three months ended September 30, 2015 and 2014 were $9.1 million and $7.5 million, respectively. Approximately $7.2 million of expenses incurred for the three months ended September 30, 2015 relate to gathering and other fees paid on our oil and natural gas production. Also included is $1.6 million of rig stacking charges. One drilling rig, whose contract began on May 1, 2015, is currently being stacked in response to the decline in crude oil prices.

In 2015, we have had reductions in our workforce due to the decrease in our drilling and developmental activities planned for the year. We incurred approximately $0.4 million in severance costs related to the termination of certain employees during the three months ended September 30, 2015.

General and administrative expense for the three months ended September 30, 2015 decreased $7.0 million to $18.0 million as compared to the same period in 2014. The decrease in general and administrative expenses results from decreases in payroll and related employee benefit costs of $2.5 million and professional fees of $3.3 million. On a per unit basis, general and administrative expenses were $4.80 per Boe and $6.23 per Boe, for the three months ended September 30, 2015 and 2014, respectively, representing a decline of 23%.

Share-based compensation expense for the three months ended September 30, 2015 was $3.0 million, a decrease of $1.6 million compared to the same period in 2014. The decrease results from forfeitures and lower fair market values for new awards granted to employees and directors subsequent to the comparable prior year period.

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 decreased $58.3 million over the prior year period. On a per unit basis, depletion expense was $19.92 per Boe for the three months ended September 30, 2015 compared to $33.18 per Boe for the three months ended September 30, 2014. The decrease in

depletion expense and the depletion rate per Boe is attributable to decreases in the amortizable base due to the full cost ceiling test impairments since the prior year period.

We utilize the full cost method of accounting to account for our oil and natural gas exploration and development activities. Under this 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 before income taxes of $511.9 million for the three months ended September 30, 2015. The ceiling test impairment for the three months ended September 30, 2015 was driven by a 17% decrease in the first-day-of-the-month average prices for crude oil used in the ceiling test calculation since June 30, 2015, when the first-day-of-the-month average price for crude oil was $71.68 per barrel. 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. See "Overview" for a discussion and quantification of potential future ceiling impairments in an environment of sustained lower commodity prices.

We enter into derivative commodity instruments to economically hedge our exposure to price fluctuations on our anticipated oil and natural gas production. Consistent with prior years, we have elected not to designate any positions as cash flow hedges for accounting purposes, and accordingly, we record the net change in the mark-to-market value of these derivative contracts in our unaudited condensed consolidated statements of operations. At September 30, 2015, we had a $401.1 million derivative asset, $327.5 million of which was classified as current, and we had a $0.6 million derivative liability, all of which was classified as non-current associated with these contracts. We recorded a net derivative gain of $204.6 million ($89.7 million net unrealized gain and $114.9 million net realized gain on settled contracts) for the three months ended September 30, 2015 compared to a net derivative gain of $163.3 million ($169.7 million net unrealized gain and $6.4 million net realized loss on settled contracts), in the same period in 2014.

Interest expense and other increased $19.5 million for the three months ended September 30, 2015 from the same period in 2014. Capitalized interest for the three months ended September 30, 2015 and 2014 was $28.8 million and $40.4 million, respectively. The decrease in capitalized interest was driven by decreases in our unevaluated properties since September 30, 2014, which is the basis of our capitalized interest calculation. Interest expense subject to capitalization increased to $86.1 million in the three months ended September 30, 2015 from $79.2 million in the comparable prior year period. The increase in interest subject to capitalization is attributed to the issuance of the Second Lien Notes on May 1, 2015.

During the three months ended September 30, 2015, we entered into separate, privately negotiated exchange agreements with holders of our senior unsecured notes whereby we agreed to issue approximately $1.02 billion aggregate principal amount of Third Lien Notes in exchange for approximately $1.57 billion aggregate principal amount of senior unsecured notes held by such holders. We recorded a net gain on the extinguishment of debt of $535.1 million, as a $548.2 million gain on the exchange agreements was partially offset by the writedown of $13.1 million associated with related issuance costs and discounts and premiums for the respective senior unsecured notes exchanged.

We recorded an income provision of $6.0 million for the three months ended September 30, 2015, compared to an income tax benefit of $1.3 million in the comparable prior period primarily due to the valuation allowance partially offset by estimated alternative minimum tax of $5.0 million and Texas franchise tax of $1.0 million. The effective tax rate for the three months ended September 30, 2015 was 3.9% compared to (0.7)% for the three months ended September 30, 2014.

We reported a net loss of $1.5 billion and net income of $57.2 million for the nine months ended September 30, 2015 and 2014, respectively. The following table summarizes key items of comparison and their related change for the periods indicated.

	Nine Months Ended September 30,

In thousands (except per unit and per Boe amounts)	2015			2014			Change
Net income (loss)	$	(1,529,178	)	$	57,194		$	(1,586,372	)
Operating revenues:
Oil		404,368			848,104			(443,736	)
Natural gas		17,595			27,965			(10,370	)
Natural gas liquids		10,572			28,396			(17,824	)
Other		1,622			4,337			(2,715	)
Operating expenses:
Production:
Lease operating		81,266			95,700			(14,434	)
Workover and other		11,614			12,550			(936	)
Taxes other than income		37,246			83,002			(45,756	)
Gathering and other		30,583			18,119			12,464
Restructuring		2,664			987			1,677
General and administrative:
General and administrative		56,853			76,273			(19,420	)
Share-based compensation		11,245			13,837			(2,592	)
Depletion, depreciation and accretion:
Depletion—Full cost		289,959			381,152			(91,193	)
Depreciation—Other		6,119			6,429			(310	)
Accretion expense		1,331			1,375			(44	)
Full cost ceiling impairment		2,014,518			61,165			1,953,353
Other operating property and equipment impairment		—			3,789			(3,789	)
Other income (expenses):
Net gain (loss) on derivative contracts		216,805			8,589			208,216
Interest expense and other, net		(180,206	)		(107,114	)		(73,092	)
Gain (loss) on extinguishment of debt		557,907			—			557,907
Gain (loss) on extinguishment of Convertible Note and modification of February 2012 Warrants		(8,219	)		—			(8,219	)
Income tax (provision) benefit		(6,224	)		1,295			(7,519	)
Production:
Oil—MBbls		9,096			9,343			(247	)
Natural Gas—Mmcf		7,444			6,192			1,252
Natural gas liquids—MBbls		1,046			755			291
Total MBoe⁽¹⁾		11,383			11,130			253
Average daily production—Boe⁽¹⁾		41,696			40,769			927
Average price per unit⁽²⁾:
Oil price—Bbl	$	44.46		$	90.77		$	(46.31	)
Natural gas price—Mcf		2.36			4.52			(2.16	)
Natural gas liquids price—Bbl		10.11			37.61			(27.50	)
Total per Boe⁽¹⁾		38.00			81.26			(43.26	)
Average cost per Boe:
Production:
Lease operating	$	7.14		$	8.60		$	(1.46	)
Workover and other		1.02			1.13			(0.11	)
Taxes other than income		3.27			7.46			(4.19	)
Gathering and other		2.69			1.63			1.06
Restructuring		0.23			0.09			0.14
General and administrative:
General and administrative		4.99			6.85			(1.86	)
Share-based compensation		0.99			1.24			(0.25	)
Depletion		25.47			34.25			(8.78	)

For the nine months ended September 30, 2015, oil, natural gas and natural gas liquids revenues decreased $471.9 million from the same period in 2014 due to lower average realized prices. Average realized prices (excluding the effects of hedging arrangements) decreased from $81.26 per Boe to $38.00 per Boe, representing a 53% decrease from the prior year period. Oil and natural gas prices are inherently volatile and decreased significantly over the latter half of 2014 and throughout 2015. Sustained lower commodity prices will continue to impact our oil, natural gas and natural gas liquids revenues. The impact of decreased prices was partially offset by increased production associated with the development of our core properties in the Bakken/Three Forks and El Halcón areas.

Lease operating expenses decreased $14.4 million for the nine months ended September 30, 2015 due to our divestiture of non-core properties in 2014 which, historically, had higher operating costs, as well as our efforts to reduce costs and become a more efficient operator. Lease operating expenses were $7.14 per Boe for the nine months ended September 30, 2015, compared to $8.60 per Boe for the same period in 2014. The decrease in lease operating expenses per Boe primarily results from our efforts to reduce costs in our core operating areas.

Taxes other than income decreased $45.8 million for the nine months ended September 30, 2015 as compared to the same period in 2014 primarily due to lower oil, natural gas and natural gas liquids revenues attributable to significantly lower commodity prices. 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 $3.27 per Boe and $7.46 per Boe for the nine months ended September 30, 2015 and 2014, respectively.

Gathering and other expenses for the nine months ended September 30, 2015 and 2014 were $30.6 million and $18.1 million, respectively. Approximately $21.1 million of expenses incurred for the nine months ended September 30, 2015 relate to gathering and other fees paid on our oil and natural gas production. Also included is a $6.0 million termination fee paid to early terminate one of our drilling rig contracts and $2.6 million of rig stacking fees. The decision to early terminate one drilling rig contract and stack another drilling rig was in response to the decline in crude oil prices.

During 2015, we have had reductions in our workforce due to the decrease in our drilling and developmental activities planned for the year. We incurred approximately $2.7 million in severance costs and accelerated stock-based compensation expense related to the termination of certain employees during the period. For the nine months ended September 30, 2014, in conjunction with our divestitures of certain non-core properties, we incurred approximately $1.0 million in severance costs and accelerated stock-based compensation expense related to the termination of certain employees in these non-core areas.

General and administrative expense for the nine months ended September 30, 2015 decreased $19.4 million to $56.9 million as compared to the same period in 2014. The decrease in general and administrative expenses results from decreases in professional fees, payroll and related employee benefit costs, and transaction expenses amounting to $8.3 million, $6.6 million and $1.3 million, respectively. On a per unit basis, general and administrative expenses were $4.99 per Boe and $6.85 per Boe, for the nine months ended September 30, 2015 and 2014, respectively.

Share-based compensation expense for the nine months ended September 30, 2015 was $11.2 million, a decrease of $2.6 million compared to the same period in 2014. The decrease results from forfeitures and lower fair market values for new awards granted to employees and directors subsequent to the comparable prior year period.

beginning of the period. Depletion expense decreased $91.2 million for the nine months ended September 30, 2015 compared to the same period in 2014, primarily attributable to decreases in the amortizable base due to the full cost ceiling impairments since the prior year period. On a per unit basis, depletion expense was $25.47 per Boe for the nine months ended September 30, 2015 compared to $34.25 per Boe for the nine months ended September 30, 2014.

We utilize the full cost method of accounting to account for our oil and natural gas exploration and development activities. Under this method of accounting, we are required on a quarterly basis to determine whether the net book value of our oil and natural gas properties (excluding unevaluated properties) is less than or equal to the "ceiling" established by 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 full cost ceiling test impairments before income taxes totaling $2.0 billion for the nine months ended September 30, 2015, compared to a full cost ceiling test impairment before income taxes of $61.2 million for the nine months ended September 30, 2014. The ceiling test impairments in 2015 were driven by decreases in the first-day-of-the-month average prices for crude oil used in the ceiling test calculations since December 31, 2014, when the first-day-of-the-month average price for crude oil was $94.99 per barrel. Changes in commodity prices, production rates, reserve volumes, future development costs, transfers of unevaluated properties, and other factors will determine our actual ceiling test calculation and impairment analyses in future periods. See "Overview" for a discussion and quantification of potential future ceiling impairments in an environment of sustained lower commodity prices.

We review our gas gathering systems and equipment and other operating assets for impairment in accordance with ASC 360. For the nine months ended September 30, 2014, we recorded a non-cash impairment charge of $3.8 million related to the disposition of midstream infrastructure assets associated with certain non-core property divestitures.

We enter into derivative commodity instruments to economically hedge our exposure to price fluctuations on our anticipated oil and natural gas 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 the unaudited condensed consolidated statements of operations. At September 30, 2015, we had a $401.1 million derivative asset, $327.5 million of which was classified as current, and we had a $0.6 million derivative liability, all of which was classified as non-current. We recorded a net derivative gain of $216.8 million ($94.0 million net unrealized loss and $310.8 million net realized gain on settled contracts) for the nine months ended September 30, 2015 compared to a net derivative gain of $8.6 million ($36.9 million net unrealized gain and $28.3 million net realized loss on settled contracts and premium costs), in the same period in 2014.

Interest expense and other increased $73.1 million for the nine months ended September 30, 2015 from the same period in 2014. Capitalized interest for the nine months ended September 30, 2015 and 2014 was $80.3 million and $129.5 million, respectively. The decrease in capitalized interest was driven by decreases in our unevaluated properties since September 30, 2014, which is the basis of our capitalized interest calculation. Interest expense subject to capitalization increased to $254.9 million in the nine months ended September 30, 2015 from $237.5 million in the comparable prior year period. The increase in interest subject to capitalization is due to our issuance of the Second Lien Notes on May 1, 2015.

During the nine months ended September 30, 2015, we entered into separate, privately negotiated exchange agreements with holders of our senior unsecured notes whereby we agreed to issue approximately $1.02 billion aggregate principal amount of Third Lien Notes in exchange for approximately $1.57 billion aggregate principal amount of senior unsecured notes held by such holders.

As a result of these exchange agreements, we recorded a net gain on the extinguishment of debt of $535.1 million, as a $548.2 million gain on the exchanges was partially offset by the writedown of $13.1 million associated with related issuance costs and discounts and premiums for the respective senior unsecured notes exchanged. In addition, we also entered into several exchange agreements with holders of our senior unsecured notes whereby the holders agreed to exchange an aggregate $258.0 million principal amount of their senior unsecured notes for approximately 144.8 million shares of our common stock. As a result of these debt for equity exchanges, we recorded a net gain on the extinguishment of debt of $22.8 million, as a $26.6 million gain on the exchanges was partially offset by the writedown of $3.8 million associated with related issuance costs and discounts and premiums for the respective senior unsecured notes exchanged.

During the nine months ended September 30, 2015, we entered into an amendment to our Convertible Note and to the February 2012 Warrants, in which we recorded a net gain on the extinguishment of the Convertible Note of $5.9 million and a net loss on the modification of the February 2012 Warrants of $14.1 million.

We recorded an income tax provision of $6.2 million for the nine months ended September 30, 2015 primarily due to the valuation allowance partially offset by estimated alternative minimum tax of $5.1 million and Texas franchise tax of $1.1 million. We recorded an income tax benefit of $1.3 million for the comparable prior period due to an offsetting valuation allowance and expected tax refunds. The effective tax rate for the nine months ended September 30, 2015 was 0.4% compared to (2.3)% for the nine months ended September 30, 2014.

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. When oil, natural gas, and natural gas liquids prices decline significantly our ability to finance our capital budget and operations may be adversely impacted. Commodity prices have been and we expect them 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 and natural gas 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, swaps, and deferred put options. 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 current and anticipated production for the next 18 to 24 months. 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 financial institutions deemed by management as competitive market makers. We did not post collateral under any of our derivative contracts as they are secured under our Senior Credit Agreement or are uncollateralized trades. Please refer to Item 1. Condensed Consolidated Financial Statements (Unaudited)—Note 6, "Derivative and Hedging Activities" for additional information.

We are also exposed to interest rate risk on our variable interest rate debt. If interest rates increase, our interest expense would increase and our available cash flows would decrease. Historically, we entered into interest rate swaps which reduce exposure to market rate fluctuations by converting variable interest rates to fixed interest rates. At September 30, 2015 and 2014, we did not have any open positions converting our variable interest rate debt to fixed interest rates. We continue to monitor our exposure to interest rate fluctuations as we incur indebtedness with variable interest rates and enter into swaps in accordance with our risk management policy when we believe it is warranted.

We account for our derivative activities under the provisions of ASC 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 6, "Derivative and Hedging Activities" for additional information.

The estimated fair values for financial instruments under ASC 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, accounts receivable and accounts payable approximates their carrying value due to their short-term nature. See Item 1. Condensed Consolidated Financial Statements (Unaudited)—Note 5, "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, 2015, total long-term debt was approximately $3.1 billion of which approximately 99% bears interest at a weighted average fixed interest rate of 10.2% per year. The remaining 1% of our total debt balance at September 30, 2015 bears interest at floating or market interest rates that, at our option, are tied to prime rate or LIBOR. Fluctuations in market interest rates will cause our annual interest costs to fluctuate. At September 30, 2015, the weighted average interest rate on our variable rate debt was 4.0% per year. If the balance of our variable rate debt at September 30, 2015 were to remain constant, a 10% change in market interest rates would impact our cash flow by approximately $0.2 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, 2015. 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 SEC 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 quarter ended September 30, 2015 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

From time to time, we 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, our management and legal counsel believe that the resolution of these proceedings through settlement or adverse judgment will not have a material effect on our consolidated operating results, financial position or cash flows.

There have been no changes to the risk factors described in our Annual Report on Form 10-K for the fiscal year ended December 31, 2014, except as described below.

We are currently out of compliance with the New York Stock Exchange's minimum share price requirement and are at risk of the NYSE delisting our common stock, which could materially impair the liquidity and value of our common stock.

Our common stock is currently listed on the New York Stock Exchange (NYSE). On August 25, 2015, we were notified by the NYSE that the average closing price of our common stock had fallen below $1.00 per share over a period of 30 consecutive trading days, which is the minimum average share price required by the NYSE. This year, through November 2, 2015, the closing price of our common stock ranged between a high of $2.23 per share on February 17, 2015 and a low of $0.53 per share on September 30, 2015. We need to bring our share price and consecutive thirty trading-day average share price, as measured on the last trading day of any calendar month during the sixth month period following receipt of the NYSE notice, above $1.00 per share or the NYSE will commence suspension and delisting procedures. In addition, if our common stock price remains below the $1.00 threshold and falls to the point where the NYSE considers the stock price to be "abnormally low," the NYSE has the discretion to begin delisting procedures immediately. There is no formal definition of "abnormally low" in the NYSE rules. Our stockholders have approved a one-for-five reverse stock split of our common stock, which can be implemented at the discretion of our board of directors at any time prior to the date of our next annual stockholders meeting; however, there can be no assurance that such action will be taken or, if taken, that a one-for-five reverse split of our common stock will bring our share price back above the $1.00 per share continued listing requirement.

A delisting of our common stock, either as result of a failure to regain compliance with the NYSE's minimum share price requirement or the Company's failure to satisfy other qualitative or quantitative standards for continued listing on the NYSE, could negatively impact us by, among other things, reducing the liquidity and market price of our common stock, reducing the number of investors willing to hold or acquire our common stock, and limiting our ability to issue additional securities or obtain additional financing in the future. Moreover, a delisting of our common stock could constitute a "fundamental change" under the terms of our 5.75% Series A Cumulative Perpetual Convertible Preferred Stock, which might require us to reserve a significantly greater number of shares of our common stock for issuance upon conversion of the preferred stock and deplete the number of authorized shares of common stock available for issuance for other purposes.

On May 7, 2015, we entered into an exchange agreement with Union Square Park Partners, L.P., a holder of our 2022 Notes and 2021 Notes, pursuant to which it agreed to exchange approximately $5.8 million principal amount of such notes for approximately 3.5 million shares of our common stock, resulting in an effective exchange price of $1.70 per share. Of the aggregate $5.8 million principal amount of senior notes exchanged by the holders, approximately $2.0 million is principal amount of 2022 Notes and approximately $3.8 million is principal amount of 2021 Notes. The exchange closed on May 15, 2015, at which time we paid all accrued and unpaid interest on the notes since the prior interest payment date for each of the 2022 Notes and 2021 Notes.

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

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.


3.1		Amended and Restated Certificate of Incorporation of Halcón Resources Corporation dated May 6, 2015 (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed May 7, 2015).

3.2		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 May 7, 2015).

4.1		Indenture dated as of September 10, 2015, by Halcón Resources Corporation, the guarantors from time to time party thereto, U.S. Bank National Association, as Trustee, the other Third Lien Representatives from time to time party thereto and U.S. Bank National Association, as Collateral Trustee (Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed September 15, 2015).

10.1		Eleventh Amendment to Senior Revolving Credit Agreement, dated as of September 10, 2015, among Halcón Resources Corporation, as borrower, each of the guarantors party thereto, each of the lenders party thereto, and JPMorgan Chase Bank, N.A., as administrative agent for the lenders (Incorporated by reference to Exhibit 10.4 of our Current Report on Form 8-K filed September 15, 2015).

10.2		Priority Confirmation Joinder, dated as of September 10, 2015, by and between JPMorgan Chase Bank, N.A., as Priority Lien Agent, and U.S. Bank National Association, as Third Lien Collateral Trustee (Incorporated by reference to Exhibit 10.3 of our Current Report on Form 8-K filed September 15, 2015).

10.3		Collateral Trust Agreement, dated as of September 10, 2015, by Halcón Resources Corporation, the guarantors from time to time party thereto, U.S. Bank National Association, as Trustee, the other Third Lien Representatives from time to time party thereto and U.S. Bank National Association, as Collateral Trustee (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed September 15, 2015).

10.4		Third Lien Security Agreement, dated as of September 10, 2015, by and among Halcón Resources Corporation, the grantors from time to time party thereto in favor of U.S. Bank National Association, as Collateral Trustee (Incorporated by reference to Exhibit 10.2 of our Current Report on Form 8-K filed September 15, 2015).

12.1	*	Computation of Ratio of Earnings to Combined Fixed Charges and Preference Dividends

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

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, 2015
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 ý		Accelerated Filer o		Non-Accelerated Filer o (Do not check if a smaller reporting company)		Smaller Reporting Company o



PART I—FINANCIAL INFORMATION
ITEM 1.	Condensed Consolidated Financial Statements (Unaudited)	5
	Condensed Consolidated Statements of Operations (Unaudited) for the Three and Nine Months Ended September 30, 2015 and 2014	5
	Condensed Consolidated Balance Sheets (Unaudited) as of September 30, 2015 and December 31, 2014	6
	Condensed Consolidated Statements of Stockholders' Equity (Unaudited) for the Nine Months Ended September 30, 2015 and Year Ended December 31, 2014	7
	Condensed Consolidated Statements of Cash Flows (Unaudited) for the Nine Months Ended September 30, 2015 and 2014	8
	Notes to Unaudited Condensed Consolidated Financial Statements	9
ITEM 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	49
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	65
ITEM 4.	Controls and Procedures	66
PART II—OTHER INFORMATION
ITEM 1.	Legal Proceedings	67
ITEM 1A.	Risk Factors	67
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	68
ITEM 3.	Defaults Upon Senior Securities	68
ITEM 4.	Mine Safety Disclosures	68
ITEM 5.	Other Information	68
ITEM 6.	Exhibits	69
Signatures		70

	September 30, 2015		December 31, 2014

	(In thousands)
Senior revolving credit facility	$	44,000	$	557,000
8.625% senior secured second lien notes due 2020⁽¹⁾		700,000		—
13.0% senior secured third lien notes due 2022⁽²⁾		1,017,994		—
9.25% senior notes due 2022⁽²⁾		98,329		400,000
8.875% senior notes due 2021⁽²⁾⁽³⁾		521,592		1,370,032
9.75% senior notes due 2020⁽²⁾⁽⁴⁾		463,806		1,151,821
8.0% convertible note due 2020⁽⁵⁾		265,508		267,883

	$	3,111,229	$	3,746,736

Year		Percentage

2017			104.313
2018			102.156
2019 and thereafter			100.000


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, 2015

	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets
Receivables from derivative contracts	$	—	$	401,118	$	—	$	401,118



Liabilities
Liabilities from derivative contracts	$	—	$	206	$	417	$	623

	September 30, 2015				December 31, 2014

Debt	Principal Amount		Estimated Fair Value		Principal Amount		Estimated Fair Value
	(In thousands)
8.625% senior secured second lien notes	$	700,000	$	586,250	$	—	$	—
13.0% senior secured third lien notes		1,017,994		647,699		—		—
9.25% senior notes		98,329		31,865		400,000		300,000
8.875% senior notes		514,671		156,975		1,350,000		1,005,750
9.75% senior notes		462,784		157,347		1,150,000		872,862
8.0% convertible note		289,669		124,789		289,669		260,643

	$	3,083,447	$	1,704,925	$	3,189,669	$	2,439,255

		Asset derivative contracts					Liability derivative contracts

Derivatives not designated as hedging contracts under ASC 815	Balance sheet location	September 30, 2015		December 31, 2014		Balance sheet location	September 30, 2015			December 31, 2014
		(In thousands)					(In thousands)
Commodity contracts	Current assets—receivables from derivative contracts	$	327,535	$	352,530	Current liabilities—liabilities from derivative contracts	$	—		$	—
Commodity contracts	Other noncurrent assets—receivables from derivative contracts		73,583		151,324	Other noncurrent liabilities—liabilities from derivative contracts		(623	)		(9,387	)

Total derivatives not designated as hedging contracts under ASC 815		$	401,118	$	503,854		$	(623	)	$	(9,387	)

	Derivative Assets						Derivative Liabilities

Offsetting of Derivative Assets and Liabilities	September 30, 2015			December 31, 2014			September 30, 2015			December 31, 2014
	(In thousands)
Gross Amounts Presented in the Consolidated Balance Sheet	$	401,118		$	503,854		$	(623	)	$	(9,387	)
Amounts Not Offset in the Consolidated Balance Sheet		(636	)		(9,655	)		623			9,387

Net Amount	$	400,482		$	494,199		$	—		$	—


Liability for asset retirement obligations as of December 31, 2014	$	38,477
Liabilities settled and divested		(324	)
Additions		2,729
Accretion expense		1,331

Liability for asset retirement obligations as of September 30, 2015	$	42,213

	Tranche rights			Embedded derivative

Balances at December 31, 2014	$	(2,634	)	$	5,963
Change in fair value		2,634			1,179

Balances at September 30, 2015	$	—		$	7,142

		Average Price Paid Per Share

July 2015	878	$	1.09	—	—
August 2015	3,319		1.10	—	—
September 2015	951		0.82	—	—


	HALCÓN RESOURCES CORPORATION
November 6, 2015	By:	/s/ FLOYD C. WILSON
		Name:	Floyd C. Wilson
		Title:	Chairman of the Board and Chief Executive Officer
November 6, 2015	By:	/s/ MARK J. MIZE
		Name:	Mark J. Mize
		Title:	Executive Vice President, Chief Financial Officer and Treasurer
November 6, 2015	By:	/s/ JOSEPH S. RINANDO, III
		Name:	Joseph S. Rinando, III
		Title:	Senior Vice President, Chief Accounting Officer and Controller