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 October 31, 2013, 414,595,678 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 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. You should consider carefully the risks discussed under the "Risk Factors" section of our previously filed Annual Report on Form 10-K for the year ended December 31, 2012, 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,

	2013			2012			2013			2012
Operating revenues:
Oil, natural gas and natural gas liquids sales:
Oil	$	288,850		$	65,670		$	672,167		$	109,050
Natural gas		7,457			3,918			19,971			6,875
Natural gas liquids		7,894			3,230			15,976			7,080

Total oil, natural gas and natural gas liquids sales		304,201			72,818			708,114			123,005
Other		806			489			2,090			560

Total operating revenues		305,007			73,307			710,204			123,565

Operating expenses:
Production:
Lease operating		37,539			14,197			94,676			30,113
Workover and other		2,029			1,123			4,276			2,384
Taxes other than income		26,613			5,814			62,616			9,648
Gathering and other		3,766			167			6,901			274
Restructuring		—			725			507			1,732
General and administrative		33,762			33,124			98,885			66,327
Depletion, depreciation and accretion		143,091			22,726			320,264			34,661
Full cost ceiling impairment		909,098			—			909,098			—
Other operating property and equipment impairment		67,254			—			67,254			—
Goodwill impairment		228,875			—			228,875			—

Total operating expenses		1,452,027			77,876			1,793,352			145,139

Income (loss) from operations		(1,147,020	)		(4,569	)		(1,083,148	)		(21,574	)
Other income (expenses):
Net gain (loss) on derivative contracts		(54,427	)		(9,575	)		(38,749	)		(849	)
Interest expense and other, net		(13,663	)		(5,074	)		(24,245	)		(22,250	)

Total other income (expenses)		(68,090	)		(14,649	)		(62,994	)		(23,099	)

Income (loss) before income taxes		(1,215,110	)		(19,218	)		(1,146,142	)		(44,673	)
Income tax benefit (provision)		360,283			(963	)		333,868			(1,171	)

Net income (loss)		(854,827	)		(20,181	)		(812,274	)		(45,844	)
Non-cash preferred dividend		—			—			—			(88,445	)
Series A preferred dividends		(5,070	)		—			(5,786	)		—

Net income (loss) available to common stockholders	$	(859,897	)	$	(20,181	)	$	(818,060	)	$	(134,289	)

Net income (loss) per share of common stock:
Basic	$	(2.19	)	$	(0.11	)	$	(2.22	)	$	(1.01	)

Diluted	$	(2.19	)	$	(0.11	)	$	(2.22	)	$	(1.01	)

Weighted average common shares outstanding:
Basic		392,726			191,846			368,696			132,460

Diluted		392,726			191,846			368,696			132,460

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, 2013			December 31, 2012

Current assets:
Cash	$	461		$	2,506
Accounts receivable		292,278			262,809
Receivables from derivative contracts		3,246			7,428
Current portion of deferred income taxes		10,992			5,307
Inventory		6,370			3,116
Prepaids and other		16,142			6,691

Total current assets		329,489			287,857

Oil and natural gas properties (full cost method):
Evaluated		4,806,377			2,669,245
Unevaluated		1,982,188			2,326,598

Gross oil and natural gas properties		6,788,565			4,995,843
Less—accumulated depletion		(1,809,963	)		(588,207	)

Net oil and natural gas properties		4,978,602			4,407,636

Other operating property and equipment:
Gas gathering and other operating assets		110,940			59,748
Less—accumulated depreciation		(10,330	)		(8,119	)

Net other operating property and equipment		100,610			51,629

Other noncurrent assets:
Goodwill		—			227,762
Receivables from derivative contracts		5,629			371
Debt issuance costs, net		63,258			51,609
Deferred income taxes		171,000			—
Equity in oil and natural gas partnerships		10,821			11,137
Funds in escrow		847			2,090
Other		11,182			934

Total assets	$	5,671,438		$	5,041,025

Current liabilities:
Accounts payable and accrued liabilities	$	695,052		$	590,551
Liabilities from derivative contracts		30,387			10,429
Asset retirement obligations		1,391			2,319
Current portion of long-term debt		695			—
Promissory notes		—			74,669

Total current liabilities		727,525			677,968

Long-term debt		3,003,855			2,034,498
Other noncurrent liabilities:
Liabilities from derivative contracts		1,146			2,461
Asset retirement obligations		86,646			72,813
Deferred income taxes		—			160,055
Other		2,510			10
Commitments and contingencies (Note 10)
Mezzanine equity:
Preferred stock: 1,000,000 shares of $0.0001 par value authorized; none and 10,880 shares of 8% Automatically Convertible, issued and outstanding as of September 30, 2013 and December 31, 2012, respectively		—			695,238
Stockholders' equity:
Preferred stock: 1,000,000 shares of $0.0001 par value authorized; 345,000 and none shares of 5.75% Cumulative Perpetual Convertible Series A, issued and outstanding as of September 30, 2013 and December 31, 2012, respectively		—			—
Common stock: 670,000,000 and 336,666,666 shares of $0.0001 par value authorized; 414,616,509 and 259,802,377 shares issued; 414,616,509 and 258,152,468 outstanding at September 30, 2013 and December 31, 2012, respectively		41			26
Additional paid-in capital		2,940,585			1,681,717
Treasury stock: none and 1,649,909 shares at September 30, 2013 and December 31, 2012, respectively, at cost		—			(9,298	)
Accumulated deficit		(1,090,870	)		(274,463	)

Total stockholders' equity		1,849,756			1,397,982

Total liabilities and stockholders' equity	$	5,671,438		$	5,041,025

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								Treasury Stock

	Preferred Stock						Common Stock					Additional Paid-In Capital			Treasury Stock						Accumulated Deficit			Stockholders' Equity
	Shares			Amount			Shares			Amount		Additional Paid-In Capital			Shares			Amount			Accumulated Deficit			Stockholders' Equity
Balances at December 31, 2011		—		$	—			27,695		$	3	$	229,414			1,450		$	(7,159	)	$	(220,578	)	$	1,680
Warrants issued		—			—			—			—		43,590			—			—			—			43,590
Sale of common stock		—			—			115,232			11		568,989			—			—			—			569,000
Reverse-stock-split rounding		—			—			4			—		—			—			—			—			—
Sale of preferred stock		4			311,556			—			—		—			—			—			—			311,556
Preferred stock conversion		(4	)		(385,476	)		44,445			5		385,471			—			—			—			—
Offering costs		—			(14,525	)		—			—		(5,078	)		—			—			—			(19,603	)
Common stock issuance		—			—			72,114			7		452,032			—			—			—			452,039
Net loss		—			—			—			—		—			—			—			(53,885	)		(53,885	)
Preferred beneficial conversion feature		—			—			—			—		88,445			—			—			—			88,445
Non-cash preferred dividend		—			88,445			—			—		(88,445	)		—			—			—			—
Long-term incentive plan grants		—			—			312			—		—			—			—			—			—
Repurchase of stock		—			—			—			—		—			200			(2,139	)		—			(2,139	)
Share-based compensation		—			—			—			—		7,299			—			—			—			7,299

Balances at December 31, 2012		—		$	—			259,802		$	26	$	1,681,717			1,650		$	(9,298	)	$	(274,463	)	$	1,397,982
Net loss		—			—			—			—		—			—			—			(812,274	)		(812,274	)
Dividend on Series A preferred stock		—			—			855			—		4,133			—			—			(4,133	)		—
Preferred stock conversion		—			—			108,801			11		695,227			—			—			—			695,238
Sale of Series A preferred stock		345			—			—			—		345,000			—			—			—			345,000
Common stock issuance		—			—			43,700			4		222,866			—			—			—			222,870
Offering costs		—			—			—			—		(17,313	)		—			—			—			(17,313	)
Long-term incentive plan grants		—			—			3,256			—		—			—			—			—			—
Long-term incentive plan forfeitures		—			—			(146	)		—		—			—			—			—			—
Reduction in shares to cover individuals' tax withholding		—			—			(1	)		—		(5	)		—			—			—			(5	)
Retirement of shares in treasury		—			—			(442	)		—		(2,492	)		(442	)		2,492			—			—
Long-term incentive plan grants issued out of treasury		—			—			(1,208	)		—		(6,806	)		(1,208	)		6,806			—			—
Share-based compensation		—			—			—			—		18,258			—			—			—			18,258

Balances at September 30, 2013		345		$	—			414,617		$	41	$	2,940,585			—		$	—		$	(1,090,870	)	$	1,849,756

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,

	2013			2012
Cash flows from operating activities:
Net income (loss)	$	(812,274	)	$	(45,844	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depletion, depreciation and accretion		320,264			34,661
Full cost ceiling impairment		909,098			—
Other operating property and equipment impairment		67,254			—
Goodwill impairment		228,875			—
Deferred income tax provision (benefit)		(334,881	)		1,030
Share-based compensation, net		11,994			3,866
Unrealized loss (gain) on derivative contracts		18,956			3,197
Amortization and write-off of deferred loan costs		1,343			6,247
Non-cash interest and amortization of discount and premium		1,395			8,620
Other income (expense)		(5,241	)		470
Change in assets and liabilities, net of acquisitions:
Accounts receivable		(83,001	)		(25,609	)
Inventory		(557	)		(1,565	)
Prepaids and other		(8,441	)		(2,179	)
Accounts payable and accrued liabilities		76,821			18,984

Net cash provided by (used in) operating activities		391,605			1,878

Cash flows from investing activities:
Oil and natural gas capital expenditures		(1,828,969	)		(716,112	)
Other operating property and equipment capital expenditures		(120,071	)		(18,133	)
Proceeds received from sales of oil and gas assets		160,268			—
Acquisition of GeoResources, Inc., net of cash acquired		—			(579,497	)
Acquisition of East Texas Assets		—			(296,139	)
Acquisition of Williston Basin Assets		(32,181	)		—
Funds held in escrow and other		(5,547	)		(2,435	)

Net cash provided by (used in) investing activities		(1,826,500	)		(1,612,316	)

Cash flows from financing activities:
Proceeds from borrowings		2,760,000			1,282,255
Repayments of borrowings		(1,858,400	)		(328,000	)
Debt issuance costs		(19,302	)		(23,657	)
Offering costs		(17,313	)		(18,535	)
Common stock repurchased		—			(2,139	)
Series A preferred stock issued		345,000			—
Preferred stock issued		—			311,556
Preferred beneficial conversion feature		—			88,445
Common stock issued		222,870			275,000
Warrants issued		—			43,590
Other		(5	)		—

Net cash provided by (used in) financing activities		1,432,850			1,628,515

Net increase (decrease) in cash		(2,045	)		18,077
Cash at beginning of period		2,506			49

Cash at end of period	$	461		$	18,126

Disclosure of non-cash investing and financing activities:
Accrued capitalized interest	$	10,549		$	11,690
Asset retirement obligations		10,077			689
Non-cash preferred dividend		—			88,445
Series A preferred dividends paid in common stock		4,133			—
Payment-in-kind interest		—			14,669
Common stock issued for GeoResources, Inc.		—			321,416
Common stock issued for the East Texas Assets		—			130,623

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. 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 2012 Annual Report on Form 10-K, as filed with the United States Securities and Exchange Commission (SEC). Please refer to the notes in the 2012 Annual Report on Form 10-K when reviewing interim financial results.

During the third quarter of 2013, the Company determined that "Net cash provided by operating activities" and "Net cash used in investing activities" for the nine month period ended September 30, 2012 were both overstated by $11.7 million as a result of the inclusion of capitalized non-cash interest in the change in "Accounts payable and accrued liabilities" line item in operating cash flows and "Oil and natural gas capital expenditures" and "Other operating property and equipment capital expenditures" in investing cash flows. The Company has corrected the error, which had no impact to the net cash flows for the period, and provided related supplemental non-cash information in the accompanying unaudited condensed consolidated statements of cash flows for the nine month period ended September 30, 2012.

As discussed in Item 8. Consolidated Financial Statements and Supplementary Data—Note 2, "Corrections of Immaterial Errors," to the Company's Annual Report on Form 10-K for the year ended December 31, 2012, the consolidated balance sheet as of December 31, 2011 was restated to reflect the correction of $4.3 million of tax basis adjustments to "Oil and natural gas properties" and "Deferred income taxes" for periods prior to January 1, 2007, and as such, the accumulated deficit and stockholders' equity balances of $262.2 million and $1.1 billion, respectively, reported on the Company's Quarterly Report on Form 10-Q for the nine months ended September 30, 2012 have been adjusted to $266.5 million and $1.1 billion, respectively.

The unaudited condensed consolidated financial statements include the accounts of Halcón and its majority-owned, controlled subsidiaries. The equity method is used to account for investments in affiliates in which the Company does not have majority ownership, but has the ability to exert significant influence. The Company's investment in an oil and natural gas limited partnership, in which the Company exerts significant influence, is accounted for under the equity method.

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, beneficial conversion feature 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 significant allowances for doubtful accounts as of September 30, 2013 or December 31, 2012.

Gas gathering systems and equipment are recorded at cost. Depreciation is calculated using the straight-line method over a 30-year estimated useful life. 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 $145.7 million and $39.9 million as of September 30, 2013 and December 31, 2012, respectively, related to the construction of its gas gathering systems before impairments.

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, leasehold improvements, fixtures, furniture and equipment, five years or the lesser of lease term; trailers, seven years; heavy equipment, ten years; and an airplane and buildings, twenty years. 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 its undiscounted cash flows, then the Company would recognize an impairment loss for the difference between the carrying amount and the current fair value. Further, the Company evaluates the remaining useful lives of its 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. For the three months ended September 30, 2013, the Company recorded a non-cash impairment charge of $67.3 million 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. The impairment relates to the Company's gross investments of $68.3 million in gas gathering infrastructure that will not be economically recoverable due to the Company's shift in exploration, drilling and developmental plans from the Woodbine to El Halcón during the third quarter of 2013. See Note 5, "Oil and natural gas properties," for additional discussion regarding related factors during the third quarter of 2013 that contributed to this impairment.

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.

Goodwill represents the excess of the purchase price over the estimated fair value of the assets acquired net of the fair value of liabilities assumed in an acquisition. ASC 350, Intangibles—Goodwill and Other (ASC 350) requires that intangible assets with indefinite lives, including goodwill, be evaluated on an annual basis for impairment or more frequently if events occur or circumstances change that could potentially result in impairment. The goodwill impairment test requires the allocation of goodwill and all other assets and liabilities to reporting units. However, the Company has only one reporting unit. The Company's goodwill as of December 31, 2012 relates to its acquisition of GeoResources. Refer to Note 4, "Acquisitions and Divestitures" for more details regarding the merger between the Company and GeoResources. The Company performs its goodwill impairment test annually, using a measurement date of July 1, or more often if circumstances require.

The Company performed its annual goodwill impairment test during the third quarter of 2013, and based on this review, the Company recorded a non-cash impairment charge of $228.9 million to reduce

the carrying value of goodwill to zero. The Company has recorded the goodwill impairment in "Goodwill impairment" in the Company's unaudited condensed consolidated statements of operations. In the first step of the goodwill impairment test, the Company determined that the fair value of its reporting unit was less than the carrying amount, including goodwill, primarily due to pricing deterioration in the NYMEX forward pricing curve coupled with less favorable oil price differentials in the Company's core areas, both factors which adversely impacted the fair value of the Company's proved reserves. Therefore, the Company performed the second step of the goodwill impairment test, which led the Company to conclude that there would be no remaining implied fair value attributable to goodwill.

In estimating the fair value of its reporting unit, the Company used a combination of the income and market approaches. For purposes of estimating the fair value of the Company's oil and natural gas proved reserves, an income approach was used which 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. In estimating the fair value of the Company's unproved acreage, a market approach was used in which a review of recent transactions involving properties in the same geographical location indicated the fair value of the Company's unproved acreage from a market participant perspective.

The estimation of the fair value of the Company's reporting unit includes the use of unobservable inputs, such as estimates of proved reserves, unproved acreage values, the weighted average cost of capital (discount rate), future pricing beyond a certain period and estimated future capital and operating costs. The use of these unobservable inputs results in the fair value estimate being classified as Level 3. Although the Company believes the assumptions and estimates used in the fair value calculation of its reporting unit 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 reporting unit and performing the goodwill impairment test are inherently uncertain and require management judgment.

In December 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2011-11, Disclosures about Offsetting Assets and Liabilities (ASU 2011-11), which enhances disclosures by requiring an entity to disclose information about netting arrangements, including rights of offset, to enable users of its financial statements to understand the effect of those arrangements on its financial position. This pronouncement was issued to facilitate comparison between financial statements prepared on the basis of accounting principles generally accepted in the United States and International Financial Reporting Standards. In addition, in January 2013, the FASB issued ASU No. 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities (ASU 2013-01), which requires clarification of the specific instruments that should be considered in the offsetting disclosures. These updates are effective for annual and interim reporting periods beginning on or after January 1, 2013 and are to be applied retroactively for all comparative periods presented. The adoption of ASU 2011-11 and ASU 2013-01 resulted in new disclosures related to the Company's derivative activities. See further information at Note 8, "Derivative and Hedging Activities."

In February 2013, the FASB issued ASU No. 2013-04, Obligations Resulting from Joint and Several Liability Arrangements for which the Total Amount of the Obligation is Fixed at the Reporting Date (ASU 2013-04). ASU 2013-04 provides guidance for the recognition, measurement, and disclosure of

obligations resulting from joint and several liability arrangements, such as debt arrangements, other contractual obligations and settled litigation and judicial rulings. This pronouncement must be applied retrospectively and is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. The Company is currently assessing the impact, if any, that the adoption of ASU 2013-04 will have on its operating results, financial position and disclosures.

In February 2013, the FASB issued ASU No. 2013-11, Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists (ASU 2013-11). ASU 2013-11 provides explicit guidance on the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. This pronouncement should be applied prospectively to all unrecognized tax benefits that exist at the effective date and retrospective application is permitted. ASU 2013-11 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. The Company is currently assessing the impact, if any, that the adoption of this pronouncement will have on its operating results and financial position.

On December 21, 2011, the Company entered into a Securities Purchase Agreement (the Purchase Agreement) with HALRES LLC, formerly Halcón Resources, LLC (HALRES). Pursuant to the Purchase Agreement, (i) HALRES purchased and the Company sold 73.3 million shares of the Company's common stock (the Shares) for a purchase price of $275 million and (ii) HALRES purchased and the Company issued a senior convertible promissory note in the original principal amount of $275 million (the 2017 Note) convertible into common stock at $4.50 per share, subject to adjustment under certain circumstances, together with five year warrants (the February 2012 Warrants) to purchase 36.7 million shares of the Company's common stock at an exercise price of $4.50 per share (the Recapitalization), subject to adjustment under certain circumstances. The 2017 Note is convertible after February 8, 2014 and if converted, would currently entitle the holder to 64.4 million shares of common stock. The Company and HALRES closed the transaction contemplated by the Purchase Agreement on February 8, 2012.

In January 2012, shareholders holding a majority of the Company's outstanding shares of common stock approved the issuance of the Shares, the 2017 Note and the February 2012 Warrants pursuant to the terms of the Purchase Agreement. Additionally, effective upon the closing (i) the Company's certificate of incorporation was amended to (a) the Company's authorized shares of common stock were increased from 100 million shares to 1.01 billion shares, both of which were before the one-for-three reverse stock split; (b) a one-for-three reverse stock split of the Company's common stock was affected (which reduced the Company's authorized shares of common stock from 1.01 billion to 336.7 million shares); and (c) the name of the Company was changed from RAM Energy Resources, Inc. to Halcón Resources Corporation; and (ii) the Company's 2006 Long-Term Incentive Plan (the Plan) was amended to increase the number of shares that may be issued under the Plan from 2.5 million to 3.7 million shares.

The closing of the transaction resulted in a change in control of the Company. Material events and items resulting from the transaction include the following:

Retroactive application of the reverse stock split is required and all share and per share information included for all periods presented in these unaudited condensed consolidated financial statements reflects the reverse stock split.

In February 2012, the transaction with HALRES resulted in an "ownership change" as defined under Section 382 of the Internal Revenue Code of 1986, as amended. As a consequence, the Company has additional limitations on its ability to use the net operating losses it accrued before the ownership change as a deduction against any taxable income the Company realizes after the ownership change.

In March 2012, the Company announced its intention to close its Plano, Texas office and begin the process of relocating key administrative functions to Houston, Texas (the Restructuring). As part of the Restructuring, the Company offered certain severance and retention benefits, collectively known as the Severance Program, to the affected employees. The total expense of the Severance Program was approximately $2.9 million and related costs were recognized as restructuring expense over the requisite service periods through May 2013, as applicable. Following is a reconciliation of the beginning and ending liability balance.

On December 6, 2012, the Company completed the acquisition of two wholly-owned subsidiaries of Petro-Hunt Holdings, LLC and Pillar Holdings, LLC (the Petro-Hunt Parties), which owned acreage prospective for the Bakken/Three Forks formations located in North Dakota, in Williams, Mountrail, McKenzie and Dunn counties (the Williston Basin Assets). The Company completed the acquisition of the Williston Basin Assets for total consideration of approximately $1.5 billion, consisting of approximately $788.2 million in cash and approximately 10,880 shares of the Company's preferred stock that automatically converted into 108.8 million shares of Halcón common stock on January 18, 2013 (equivalent to a conversion price of approximately $7.45 per share of Halcón common stock based on the liquidation preference), following stockholder approval of such conversion and an amendment to Halcón's certificate of incorporation to increase the number of shares of common stock that Halcón is authorized to issue (the Williston Basin Acquisition). The Williston Basin Acquisition significantly expanded the Company's presence in North Dakota, adding undeveloped acreage, oil and natural gas reserves and production to its existing asset base and operations in this area.

The transaction had an effective date of June 1, 2012 and was subject to customary closing conditions, as well as the execution and delivery of certain other agreements, including a Registration Rights Agreement, dated December 6, 2012. In accordance with the Registration Rights Agreement, as amended, on September 27, 2013, the Company filed a shelf registration statement providing for the resale of shares of the Company's common stock issued to the Petro-Hunt Parties in the acquisition.

On August 1, 2012, the Company completed an acquisition of GeoResources, Inc. (GeoResources) by means of the merger of GeoResources into a wholly-owned subsidiary of the Company (the Merger) and began reflecting GeoResources' results of operations in the Company's unaudited condensed consolidated statements of operations. In connection with the Merger, each share of GeoResources

common stock issued and outstanding immediately prior to the effective date of the Merger was converted into the right to receive $20.00 in cash and 1.932 shares of the Company's common stock.

In the Merger, the Company issued a total of approximately 51.3 million shares of its common stock and paid approximately $531.5 million in cash to former GeoResources stockholders, resulting in a total purchase price plus liabilities assumed of approximately $1.3 billion. The acquisition expanded the Company's presence in the Bakken/Three Forks formations of North Dakota and Montana, and the Austin Chalk trend and Eagle Ford Shale in Texas, adding oil and natural gas reserves and production to its existing asset base in these areas.

In August 2012, the Company completed the acquisition of oil and gas leaseholds in East Texas (the East Texas Assets) from CH4 Energy II, LLC, PetroMax Leon, LLC, Petro Texas LLC, King King LLC and several other selling parties for total consideration of $426.8 million comprised of $296.1 million in cash and 20.8 million shares of the Company's common stock (the East Texas Acquisition). The effective date of the East Texas Acquisition was April 1, 2012. The East Texas Acquisition expanded the Company's presence in East Texas, adding oil and natural gas reserves and production to its existing asset base in this area.

As disclosed in the Company's Annual Report on Form 10-K for the year ended December 31, 2012, the acquisitions of the Williston Basin Assets and the East Texas Assets, as well as the Merger were accounted for as business combinations in accordance with Accounting Standards Codification (ASC) No. 805, Business Combinations (ASC 805) which, among other things, requires assets acquired and liabilities assumed to be measured at their acquisition date fair values. Certain assets and liabilities may be adjusted as additional information is obtained, but no later than one year from the respective acquisition dates. The purchase price for the Williston Basin Assets is still preliminary due to the use of estimates based on information that was available to management. During the nine months ended September 30, 2013, there were no adjustments to the purchase price of the East Texas Assets; however, there were minor adjustments to the respective purchase prices of GeoResources and the Williston Basin Assets related to accruals, settlements and working capital changes as a result of better information obtained during the period.

The following unaudited pro forma combined results of operations are provided for the three and nine months ended September 30, 2012 as though the Merger, the East Texas Acquisition and the Williston Basin Acquisition had been completed as of the beginning of the comparable prior annual reporting period, or January 1, 2011. The pro forma combined results of operations for the three and nine months ended September 30, 2012 have been prepared by adjusting the historical results of the Company to include the historical results of GeoResources, the East Texas Assets and the Williston Basin Assets. These supplemental pro forma results of operations are provided for illustrative purposes only and do not purport to be indicative of the actual results that would have been achieved by the combined company for the period presented or that may be achieved by the combined company in the future. The pro forma results of operations do not include any cost savings or other synergies that resulted, or may result, from the Merger, the East Texas Acquisition and the Williston Basin Acquisition, or any estimated costs that will be incurred to integrate GeoResources, the Williston Basin

Assets and the East Texas Assets. Future results may vary significantly from the results reflected in this unaudited pro forma financial information because of future events and transactions, as well as other factors.

The Company's historical financial information was adjusted to give effect to the pro forma events that were directly attributable to the Merger, the East Texas Acquisition and the Williston Basin Acquisition, and that were factually supportable. Adjustments and assumptions made for this pro forma calculation are consistent with those used in the Company's annual pro forma information, as more fully described in Item 8. Consolidated Financial Statements and Supplementary Data—Note 5, "Acquisitions and Divestitures" to the Company's Annual Report on Form 10-K for the year ended December 31, 2012.

On July 19, 2013, the Company completed the sale of its interest in Eagle Ford Shale assets located in Fayette and Gonzales Counties, Texas, previously acquired as part of the Merger, to private buyers for proceeds of approximately $147.9 million, before post-closing adjustments. The transaction had an effective date of January 1, 2013. 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. During the three months ended September 30, 2013, the Company transferred $655.7 million of unevaluated property costs to the full cost pool primarily related to Woodbine assets in East Texas where capital has been reallocated to El Halcón, and certain Utica/Point Pleasant assets in Northwest Pennsylvania related to non-economical drilling results obtained in the third quarter of 2013.

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 three and nine months ended September 30, 2013, the Company capitalized interest costs of $52.6 million and $157.6 million, respectively. For the three and nine months ended September 30, 2012, the Company capitalized interest costs of $19.4 million and $22.8 million, respectively.

At September 30, 2013 the ceiling test value of the Company's reserves was calculated based on the first-day-of-the-month average of the 12-months ended September 30, 2013 of the West Texas Intermediate (WTI) spot price of $95.20 per barrel, adjusted by lease or field for quality, transportation fees, and regional price differentials, and the first-day-of-the-month average of the 12-months ended September 30, 2013 of the Henry Hub price of $3.61 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, 2013 exceeded the ceiling amount. As a result, the Company recorded a full cost ceiling test impairment before income taxes of $909.1 million and $574.8 million after taxes. The combined impact of less favorable oil price differentials adversely affecting proved reserve values and the aforementioned transfers of unevaluated Woodbine and Utica properties to the full cost pool contributed to the ceiling impairment. The Company has recorded the full cost ceiling test impairment 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. In addition, the full cost ceiling impairment contributed to the change in the Company's deferred tax liability as of December 31, 2012 to a deferred tax asset at September 30, 2013. Changes in production rates, levels of reserves, future development costs, transfers of unevaluated properties, and other factors will determine the Company's actual ceiling test calculation and impairment analyses in future periods.

At September 30, 2012 the ceiling test value of the Company's reserves was calculated based on the first-day-of-the-month average of the 12-months ended September 30, 2012 of the WTI spot price of $94.97 per barrel, adjusted by lease or field for quality, transportation fees, and regional price differentials, and the first-day-of-the-month average of the 12-months ended September 30, 2012 of the Henry Hub price of $2.83 per Mmbtu, adjusted by lease or field for energy content, transportation fees, and regional price differentials. Using these prices, the Company's net book value of oil and natural gas properties at September 30, 2012 did not exceed the ceiling amount.

Long-term debt as of September 30, 2013 and December 31, 2012 consisted of the following:

⁽¹⁾: Table excludes $0.7 million of deferred premiums on derivative contracts which were classified as current at September 30, 2013. Table excludes $74.7 million of promissory notes which were classified as current at December 31, 2012.
⁽²⁾: On August 13, 2013, the Company completed the issuance of $400 million principal amount of its 9.25% Senior Notes due 2022. See "9.25% Senior Notes" below for more details.
⁽³⁾: Amount is net of a $5.2 million and a $5.6 million unamortized discount at September 30, 2013 and December 31, 2012, respectively, related to the issuance of the original 2021 Notes. On January 14, 2013, the Company completed the issuance of an additional $600 million principal amount of its 8.875% Senior Notes. The unamortized premium related to these additional 2021 Notes was approximately $28.1 million at September 30, 2013. See "8.875% Senior Notes" below for more details.
⁽⁴⁾: Amount is net of a $9.1 million and a $9.8 million unamortized discount at September 30, 2013 and December 31, 2012, respectively. See "9.75% Senior Notes" below for more details.
⁽⁵⁾: Amount is net of a $32.3 million and a $37.8 million unamortized discount at September 30, 2013 and December 31, 2012, respectively. See "8.0% Convertible Note" below for more details.

In connection with the closing of the Recapitalization, discussed in Note 2, "Recapitalization," 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 on February 8, 2012. The Senior Credit Agreement provides for a $1.5 billion facility with a current borrowing base of $850.0 million that was affirmed in the redetermination that occurred on October 31, 2013, subject to a reduction to $800.0 million upon the closing of all three non-core divestitures discussed in Note 15, "Subsequent Event." Amounts borrowed under the Senior Credit Agreement will mature on February 8, 2017. 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 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 five-year term of the revolver. Amounts outstanding under the Senior Credit Agreement bear interest at specified margins over the base rate of 0.50% to 1.50% for ABR-based loans or at specified margins over LIBOR of 1.50% to 2.50% for Eurodollar-based loans. These margins fluctuate based on the Company's utilization of the facility. Advances under the Senior Credit Agreement are secured by liens on substantially all of the Company's 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 minimum coverage of interest expenses (as defined in the Senior Credit Agreement) of not less than 2.5 to 1.0.

At September 30, 2013, under the then effective borrowing base of $710.0 million, the Company had $232.0 million of indebtedness outstanding, $1.2 million of letters of credit outstanding and $476.8 million of borrowing capacity available under the Senior Credit Agreement.

On January 25, 2013, the Company entered into the Second Amendment (the Second Amendment) which amends the Senior Credit Agreement with respect to the Company's ability to enter into certain commodity hedging agreements. The Second Amendment provides, among other things, that the Company and its subsidiaries may enter into commodity swap, collar and/or call option agreements with approved counterparties so long as the volumes for such agreements do not exceed 85% of the Company's internally forecasted production from (i) the Company's crude oil, natural gas liquids and natural gas, or (ii) in the case of a proposed acquisition of oil and gas properties, such oil and gas properties that are the subject of such proposed acquisition, in each case for the 24 months following the date such agreement is entered into. Additionally, the Company may enter into commodity swap, collar and/or call option agreements so long as the volumes for such agreements do not exceed 85% of (i) the reasonably anticipated projected production from the Company's proved reserves for the period of 25 to 66 months following the date such agreement is entered into, or (ii) in the case of a proposed acquisition of oil and gas properties, the reasonably anticipated projected production from proved reserves from such oil and gas properties that are the subject of such proposed acquisition for the period of 25 to 48 months following the date such agreement is entered into. The 85% limitations discussed above do not apply to volumes hedged by the Company using puts, floors and/or basis differential swap agreements.

Prior to the Second Amendment, the volumes for commodity swap, collar and/or call option agreements under the Senior Credit Agreement could not exceed 85% of the reasonably anticipated projected production from the Company's proved reserves (as forecast based upon the most recently delivered reserve report), for each month during the period during which the agreement was in effect for each of crude oil, natural gas liquids and natural gas, for the 66 months following the date such agreement was entered into.

On April 26, 2013, the Company entered into the Third Amendment to the Senior Credit Agreement which amends the Senior Credit Agreement in order to provide, among other things, additional flexibility under certain affirmative and negative covenants.

On May 8, 2013, the Company entered into the Fourth Amendment to the Senior Credit Agreement (the Fourth Amendment). The Fourth Amendment provides for modifications to the

calculation that measures compliance with the interest coverage test. The provisions of the Fourth Amendment are superseded by the Sixth Amendment discussed herein.

On June 11, 2013, the Company entered into the Fifth Amendment to the Senior Credit Agreement (the Fifth Amendment). The Fifth Amendment permits, among other things, the Company to pay cash dividends to holders of the Company's preferred capital stock.

On October 31, 2013, the Company entered into the Sixth Amendment to the Senior Credit Agreement (the Sixth Amendment). The Sixth Amendment increases the borrowing base to $850.0 million with an automatic reduction to $800.0 million upon the closing of all three non-core divestitures discussed in Note 15, "Subsequent Event." Additionally, the Sixth Amendment provides for EBITDA (as defined in the Senior Credit Agreement) to be annualized for the next three fiscal quarters for purposes of measuring compliance with the interest coverage test. Specifically, (i) for the fiscal quarter ended December 31, 2013, the Interest Coverage Ratio shall be calculated by utilizing EBITDA for the three month period then ended multiplied by 4; (ii) for the fiscal quarter ended March 31, 2014, the Interest Coverage Ratio shall be calculated by utilizing EBITDA for the six month period then ended multiplied by 2; and (iii) for the fiscal quarter ended June 30, 2014, the Interest Coverage Ratio shall be calculated by utilizing EBITDA for the nine month period then ended multiplied by ⁴/3.

At September 30, 2013, the Company was in compliance with the financial debt covenants under the Senior Credit Agreement.

On August 13, 2013, the Company issued at par $400 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, rank equally with all of its current and future senior indebtedness and are jointly and severally, fully and unconditionally guaranteed on a senior unsecured basis by the Company's existing 100% owned subsidiaries. Halcón, the issuer of the 2022 Notes, has no material independent assets or operations apart from the assets and operations of its subsidiaries.

In connection with the sale of the 2022 Notes, the Company entered into a registration rights agreement, pursuant to which the Company agreed to conduct a registered exchange offer for the 2022 Notes or cause to become effective a shelf registration statement providing for the resale of the 2022 Notes. In connection with the exchange offer, the Company is required to (a) file an exchange offer registration statement and use its reasonable best efforts to cause such registration statement to become effective, (b) promptly following the effectiveness of such registration statement, offer to exchange new registered notes having terms substantially identical to the 2022 Notes for outstanding 2022 Notes, and (c) keep the registered exchange offer open for not less than 20 business days after the date notice of the exchange offer is mailed to the holders of the 2022 Notes. If the exchange offer is not consummated within 365 days after August 13, 2013, or upon the occurrence of certain other contingencies, the Company has agreed to file a shelf registration statement to cover resales of the 2022 Notes by holders who satisfy certain conditions relating to the provision of information in

connection with the shelf registration statement. If the Company fails to comply with certain obligations under the registration rights agreement it will be required to pay liquidated damages in the form of additional cash interest to the holders of the 2022 Notes.

On or before August 15, 2016, the Company may redeem up to 35% of the aggregate principal amount of the 2022 Notes with the net cash proceeds of certain equity offerings at a redemption price of 109.250% of the principal amount plus accrued and unpaid interest to the redemption date provided that: at least 65% in aggregate principal amount of the 2022 Notes originally issued remains outstanding immediately after the redemption and the redemption occurs within 180 days of the related equity offering. In addition, at any time prior to August 15, 2017, the Company may redeem some or all of the 2022 Notes for the principal amount thereof, plus accrued and unpaid interest plus a make whole premium equal to the excess, if any of (a) the present value at such time of (i) the redemption price of such note at August 15, 2017, plus (ii) any required interest payments due on the notes through August 15, 2017 (excluding currently accrued and unpaid interest) computed using a discount rate equal to the Treasury Rate plus 50 basis points, discounted to the redemption date on a semi-annual basis, over (b) the principal amount of such note.

On November 6, 2012, the Company issued $750 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 Williston Basin Acquisition.

On January 14, 2013, the Company issued an additional $600 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 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. Halcón, the issuer of the 2021 Notes, has no material independent assets or operations apart from the assets and operations of its subsidiaries.

On June 4, 2013, the Company completed a registered exchange offer of outstanding 2021 Notes for new registered notes having terms substantially identical to the 2021 Notes.

On or before November 15, 2015, the Company may redeem up to 35% of the aggregate principal amount of the 2021 Notes with the net cash proceeds of certain equity offerings at a redemption price of 108.875% of the principal amount plus accrued and unpaid interest to the redemption date provided that: at least 65% in aggregate principal amount of the 2021 Notes originally issued remains outstanding immediately after the redemption and the redemption occurs within 180 days of the date of

closing of the related equity offering. In addition, at any time prior to November 15, 2016, the Company may redeem some or all of the 2021 Notes for the principal amount thereof, plus accrued and unpaid interest plus a make whole premium equal to the excess, if any of (a) the present value at such time of (i) the redemption price of such note at November 15, 2016, plus (ii) any required interest payments due on the notes through November 15, 2016 (excluding currently accrued and unpaid interest) computed using a discount rate equal to the Treasury Rate plus 50 basis points, discounted to the redemption date on a semi-annual basis, over (b) the principal amount of such note.

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 $5.2 million at September 30, 2013. 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 $28.1 million at September 30, 2013.

On July 16, 2012, the Company issued $750 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 and the East Texas Acquisition.

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 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. Halcón, the issuer of the 2020 Notes, has no material independent assets or operations apart from the assets and operations of its subsidiaries.

On June 4, 2013, the Company completed a registered exchange offer of outstanding 2020 Notes for new registered notes having terms substantially identical to the 2020 Notes.

On or before July 15, 2015, the Company may redeem up to 35% of the aggregate principal amount of the 2020 Notes with the net cash proceeds of certain equity offerings at a redemption price of 109.750% of the principal amount plus accrued and unpaid interest to the redemption date provided that: at least 65% in aggregate principal amount of the 2020 Notes originally issued remains outstanding immediately after the redemption and the redemption occurs within 180 days of the equity offering. In addition, at any time prior to July 15, 2016, the Company may redeem some or all of the 2020 Notes for the principal amount thereof, plus accrued and unpaid interest plus a make whole premium equal to the excess , if any of (a) the present value at such time of (i) the redemption price of such note at July 15, 2016, plus (ii) any required interest payments due on the notes through July 15, 2016 (excluding currently accrued and unpaid interest) computed using a discount rate equal to the Treasury Rate plus 50 basis points, discounted to the redemption date on a semi-annual basis, over (b) the principal amount of such note.

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 $9.1 million at September 30, 2013.

On February 8, 2012, the Company issued the 2017 Note in the principal amount of $275.0 million together with the February 2012 Warrants for an aggregate purchase price of $275.0 million. The 2017 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 and matures on February 8, 2017. Through the March 31, 2014 interest payment date, the Company may elect to pay the interest in kind, by adding to the principal of the 2017 Note, all or any portion of the interest due on the 2017 Note. The Company elected to pay the interest in kind on March 31, June 30 and September 30, 2012, and rolled $3.2 million, $5.7 million and $5.8 million of interest incurred during the first, second and third quarters of 2012, respectively, into the 2017 Note, increasing the principal amount to $289.7 million. The Company did not elect to pay-in-kind interest for the quarterly payments due subsequent to September 30, 2012. At any time after February 8, 2014, the noteholder may elect to convert all or any portion of the principal amount and accrued but unpaid interest into common stock. Each $4.50 of principal and accrued but unpaid interest is convertible into one share of the Company's common stock. The 2017 Note is a senior unsecured obligation of the Company.

The Company allocated the proceeds received for the 2017 Note and February 2012 Warrants on a relative fair value basis. Consequently, the Company recorded a discount of $43.6 million to be amortized over the remaining life of the 2017 Note utilizing the effective interest rate method. The remaining unamortized discount was $32.3 million at September 30, 2013.

On December 28, 2012, the Company completed the acquisition of certain oil and natural gas properties in Brazos County, Texas for approximately $83.7 million, before and subject to, customary closing adjustments, consisting of approximately $8.4 million in cash and approximately $75.3 million in promissory notes. During the three months ended March 31, 2013, the Company completed its review of the properties and paid approximately $62.4 million during the period for properties deemed to have clear title and no defects. In addition, notice was given to the sellers of the Company's assertion of title and environmental defects amounting to $12.9 million for the remaining properties. During the three months ended September 30, 2013, the title and environmental defects were cured by the sellers and the Company paid the remaining portion of the purchase price. The promissory notes were classified as current at December 31, 2012.

In conjunction with the issuance of the promissory notes in December 2012, the Company recorded a discount of approximately $0.6 million to be amortized over the remaining life of the promissory notes using the effective interest method. The Company expensed the discount during the first quarter of 2013.

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. During the first nine months of 2013, the Company capitalized approximately $19.3 million in costs associated with the issuance of the 2022

Notes, the additional 2021 Notes and costs incurred for amendments to the Company's Senior Credit Agreement and expensed $1.9 million of debt issuance costs in conjunction with the decreases in the Company's borrowing base under the Senior Credit Agreement. At September 30, 2013 and December 31, 2012, the Company had approximately $63.3 million and $51.6 million, respectively, of unamortized debt issuance costs.

Pursuant to 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, 2013 and December 31, 2012. 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, 2013.

Derivative contracts listed above include collars, swaps and put options 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 markets prices and implied volatility factors related to changes in the forward curves. See Note 8, "Derivative and Hedging Activities" for additional discussion of derivatives.

As of September 30, 2013 and December 31, 2012, the Company's derivative contracts were with major financial institutions with investment grade credit ratings which are believed to have a 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. Each of the counterparties to the Company's current derivative contracts is a lender or an affiliate of a lender in the Company's Senior Credit Agreement. The Company did not post collateral under any of these contracts as they are secured under the Senior Credit Agreement.

Warrants listed above at December 31, 2012 were carried at fair value. The Company recorded the net change in fair value on the August 2012 Warrants in "Interest expense and other, net" in the Company's unaudited condensed consolidated statements of operations. At December 31, 2012 and March 31, 2013, the Company valued the August 2012 Warrants based on observable market data, including treasury rates, historical volatility and data for similar instruments which resulted in the Company reporting its warrants as Level 2. During the nine months ended September 30, 2013, the Company recorded a gain of $1.6 million for the expiration of the warrants. See Note 11, "Preferred Stock and Stockholders' Equity" for additional discussion on the terms of the warrants.

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 receivable and accounts payable approximates their carrying value due to their short-term nature. The estimated fair value of the Company's Senior Credit Agreement and the promissory notes 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, 2013 and December 31, 2012 (excluding discounts, premiums and deferred premiums on derivative contracts):

The fair value of the Company's fixed interest debt instruments was calculated using Level 2 criteria at September 30, 2013 and December 31, 2012.

During the three months ended September 30, 2013, the Company recorded a non-cash impairment charge of $67.3 million related to its gas gathering systems. 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.

As of July 1, 2013, the Company performed its annual goodwill impairment test which involved the fair value estimation of the Company's reporting unit. See Note 1, "Financial Statement Presentation," for a discussion of the valuation approaches used and the classification of the estimate within the fair value hierarchy.

The Company follows the provisions of ASC 820, for nonfinancial assets and liabilities measured at fair value on a non-recurring basis. These provisions apply to the Company's initial recognition of asset retirement obligations for which fair value is used. The asset retirement obligation estimates are derived from historical costs and management's expectation of future cost environments; and therefore, the Company has designated these liabilities as Level 3. See Note 9, "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. Historically, the Company has also entered into interest rate swaps to mitigate exposure to market rate fluctuations.

It is the Company's policy to enter into derivative contracts, including interest rate derivatives, only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. Each of the counterparties to the Company's current derivative contracts is a lender or an affiliate of a lender in its Senior Credit Agreement. The Company did not post collateral under any of these contracts as they are secured under the Company's Senior Credit Agreement.

At September 30, 2013 and December 31, 2012, the Company's crude oil and natural gas derivative positions consisted of swaps, costless put/call "collars" and put options. 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. 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. A sold put option limits the exposure of the counterparty's risk should the price fall below the strike price. Sold put options limit the effectiveness of purchased put options at the low end of the put/call collars to market prices in excess of the strike price of the put option sold. The Company has elected to not 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.

In February 2012, pursuant to the Senior Credit Agreement, the Company novated its oil and natural gas derivative instruments to counterparties that are lenders or affiliates of lenders within the Senior Credit Agreement resulting in a realized loss of $0.4 million for novation fees and terminated the interest rate derivatives resulting in a $0.6 million realized loss during the three months ended March 31, 2012.

At September 30, 2013, the Company had 90 open commodity derivative contracts summarized in the following tables: 16 natural gas collar arrangements, one natural gas swap, 63 crude oil collar arrangements, five crude oil three-way collars, one crude oil put option, and four crude oil swaps.

At December 31, 2012, the Company had 47 open commodity derivative contracts summarized in the following tables: two natural gas collar arrangements, two natural gas swaps, one natural gas basis swap, 28 crude oil collar arrangements, 10 crude oil three-way collars, and four crude oil swaps.

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, 2013 and December 31, 2012:

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		2013			2012			2013			2012
		(In thousands)						(In thousands)
Commodity contracts:
Unrealized gain (loss) on commodity contracts	Other income (expenses)—net gain (loss) on derivative contracts	$	(38,095	)	$	(11,817	)	$	(20,379	)	$	(4,641	)
Realized gain (loss) on commodity contracts	Other income (expenses)—net gain (loss) on derivative contracts		(16,332	)		2,242			(18,370	)		3,850

Total net gain (loss) on commodity contracts		$	(54,427	)	$	(9,575	)	$	(38,749	)	$	(791	)

Interest rate swaps:
Unrealized gain (loss) on interest rate swaps	Other income (expenses)—net gain (loss) on derivative contracts	$	—		$	—		$	—		$	518
Realized gain (loss) on interest rate swaps	Other income (expenses)—net gain (loss) on derivative contracts		—			—			—			(576	)

Total net gain (loss) on interest rate swaps		$	—		$	—		$	—		$	(58	)

Total net gain (loss) on derivative contracts	Other income (expenses)—net gain (loss) on derivative contracts	$	(54,427	)	$	(9,575	)	$	(38,749	)	$	(849	)

At September 30, 2013 and December 31, 2012, the Company had the following open crude oil and natural gas derivative contracts:

			September 30, 2013

					Floors			Ceilings			Put Options Sold
Period	Instrument	Commodity	Volume in Mmbtu's/ Bbl's		Price / Price Range	Weighted Average Price		Price / Price Range	Weighted Average Price		Price / Price Range		Weighted Average Price
October 2013 - December 2013	Collars	Crude Oil		2,280,850	$80.00 - 100.00	$	90.29	$91.65 - 107.25	$	98.62
October 2013 - December 2013	Collars	Natural Gas		2,622,000	3.50 - 4.00		3.78	3.95 - 4.49		4.28
October 2013 - December 2013	Swaps	Crude Oil		90,000	97.60 - 105.55		102.18
October 2013 - December 2013	Swaps	Natural Gas		60,000	3.56		3.56
January 2014 - March 2014	Three-Way Collars	Crude Oil		144,000	95.00		95.00	98.60 - 109.50		100.03		70.00		70.00
January 2014 - June 2014	Collars	Crude Oil		724,000	90.00		90.00	96.50 - 99.50		98.00
January 2014 - December 2014	Collars	Crude Oil		7,573,750	85.00 - 95.00		88.67	93.60 - 108.45		96.22
January 2014 - December 2014	Collars	Natural Gas		11,862,500	3.75 - 4.00		3.85	4.26 - 4.55		4.35
April 2014 - June 2014	Three-Way Collars	Crude Oil		136,500	95.00		95.00	98.20 - 101.00		99.13		70.00		70.00
July 2014 - December 2014	Collars	Crude Oil		920,000	87.50 - 90.00		89.50	92.50 - 100.25		97.87
July 2014 - December 2014	Collars	Natural Gas		920,000	4.00		4.00	4.42		4.42
July 2014 - December 2014	Put	Crude Oil		184,000								90.00		90.00
January 2015 - June 2015	Collars	Crude Oil		678,750	85.00 - 90.00		88.00	92.50 - 98.50		95.72
January 2015 - December 2015	Collars	Crude Oil		1,095,000	90.00		90.00	99.35 - 100.25		99.87
January 2015 - December 2015	Collars	Natural Gas		6,387,500	4.00		4.00	4.55 - 4.85		4.68

			December 31, 2012

					Floors			Ceilings			Put Options Sold
Period	Instrument	Commodity	Volume in Mmbtu's/ Bbl's		Price / Price Range	Weighted Average Price		Price / Price Range	Weighted Average Price		Price / Price Range		Weighted Average Price
January 2013 - March 2013	Three-Way Collars	Crude Oil		130,500	$95.00 - 100.00	$	95.34	$105.50 - 109.50	$	101.36	$	70.00	$	70.00
January 2013 - March 2013	Basis Swaps	Natural Gas		225,000
January 2013 - March 2013	Collars	Crude Oil		31,500	95.00		95.00	101.50		101.50
January 2013 - March 2013	Swaps	Natural Gas		225,000	4.85		4.85
April 2013 - June 2013	Three-Way Collars	Crude Oil		120,575	95.00		95.00	99.50 - 100.60		99.77		70.00		70.00
April 2013 - June 2013	Collars	Crude Oil		29,575	95.00		95.00	100.60		100.60
July 2013 - September 2013	Collars	Crude Oil		147,200	95.00		95.00	99.00 - 101.50		99.94
October 2013 - December 2013	Collars	Crude Oil		142,600	95.00		95.00	99.00 - 101.00		99.71
January 2013 - December 2013	Collars	Crude Oil		5,201,250	80.00 - 100.00		89.04	91.65 - 107.25		98.06
January 2013 - December 2013	Collars	Natural Gas		1,825,000	3.75		3.75	4.26		4.26
January 2013 - December 2013	Swaps	Natural Gas		240,000	3.56		3.56
January 2013 - December 2013	Swaps	Crude Oil		360,000	97.60 - 105.55		102.18
February 2013 - December 2013	Collars	Crude Oil		250,500	100.00		100.00	104.15		104.15
April 2014 - June 2014	Three-Way Collars	Crude Oil		136,500	95.00		95.00	98.20 - 101.00		99.13		70.00		70.00
January 2014 - March 2014	Three-Way Collars	Crude Oil		144,000	95.00		95.00	98.60 - 109.50		100.03		70.00		70.00
January 2014 - December 2014	Collars	Crude Oil		2,190,000	85.00		85.00	95.10 - 96.35		95.92
January 2014 - December 2014	Collars	Natural Gas		1,825,000	3.75		3.75	4.26		4.26

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,

2013 and December 31, 2012 in accordance with ASU 2011-11 and ASU 2013-01, which were effective beginning January 1, 2013:

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) 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, 2013 (in thousands, inclusive of the current portion):

The Company leases corporate office space in Houston, Texas; Tulsa, Oklahoma; Denver, Colorado; and Williston, North Dakota as well as a number of other field office locations. Rent expense was approximately $6.8 million and $2.2 million for the nine months ended September 30, 2013 and 2012, respectively. 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 2015. Early termination of the drilling rig commitments would result in termination penalties approximating $35.5 million, which would be in lieu of the remaining $57.4 million of drilling rig commitments as of September 30, 2013. As of September 30, 2013, the amount of commitments under office and equipment lease agreements is consistent with the levels at December 31, 2012, as disclosed in the Company's Annual Report on Form 10-K, approximating $67.6 million in the aggregate, and containing various expiration dates through 2024.

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 February 29, 2012 (the Commitment Date), the Company entered into definitive agreements with a group of certain institutional and selected other accredited investors (collectively, the investors) to sell, in a private offering, 4,444.4511 shares of 8% Automatically Convertible Preferred Stock, par value $0.0001 per share (the Preferred Stock), each share of which was convertible into 10,000 shares of common stock. Also on February 29, 2012, the Company received an executed written consent (the Consent) in lieu of a stockholders' meeting authorizing and approving the conversion of the Preferred Stock into common stock. On March 2, 2012, the Company filed a Certificate of Designation, Preferences, Rights and Limitations of the Preferred Stock (the Certificate of Designation) with the Delaware Secretary of State which stated the conversion was to occur on the twentieth day after the mailing of a definitive information statement to stockholders. On March 5, 2012, the Company issued the Preferred Stock to the investors at $90,000 per share. Gross proceeds from the offering were approximately $400.0 million, or $9.00 per share of common stock, before offering expenses. The Company incurred placement agent fees of $14.0 million and associated expenses of approximately $0.5 million in connection with this offering. On March 28, 2012, the Company mailed a definitive information statement to its common stockholders notifying them that Halcón's majority stockholder had consented to the issuance of common stock, par value $0.0001, upon the conversion of the Preferred Stock. The Preferred Stock automatically converted into 44.4 million shares of common stock on April 17, 2012 in accordance with the terms of the Certificate of Designation. No cash dividends were paid on the Preferred Stock since pursuant to the terms of the Certificate of Designation of the Preferred Stock, conversion occurred prior to May 31, 2012. On November 30, 2012, the Company filed

a Certificate of Elimination with the Delaware Secretary of State eliminating all provisions of the Certificate of Designation of the Preferred Stock.

In accordance with ASC 470, Debt (ASC 470), the Company determined that the conversion feature in the Preferred Stock represented a beneficial conversion feature. The fair value of the common stock of $10.99 per share on the Commitment Date was greater than the conversion price of $9.00 per share of common stock, representing a beneficial conversion feature of $1.99 per share of common stock, or $88.4 million in aggregate. Under ASC 470, $88.4 million (the intrinsic value of the beneficial conversion feature) of the proceeds received from the issuance of the Preferred Stock was allocated to additional paid-in capital, creating a discount on the Preferred Stock (the Discount). The Discount resulting from the allocation of value to the beneficial conversion feature was required to be amortized on a non-cash basis over the approximate 71-month period between the issuance date and the required redemption date of February 9, 2018, or fully amortized upon an accelerated date of redemption or conversion, and recorded as a preferred dividend. As a result, approximately $1.1 million of the Discount was amortized and a non-cash preferred dividend was recorded in the first quarter of 2012 and due to the conversion date occurring on April 17, 2012, the remaining $87.3 million of Discount amortization was accelerated to the conversion date and was fully amortized in the second quarter of 2012 as per the guidance of ASC 470. The Discount amortization is reflected as non-cash preferred dividend in the unaudited condensed consolidated statements of operations. In accordance with the guidance in ASC 480, the preferred dividend was charged against additional paid-in capital since no retained earnings were available.

On December 6, 2012, the Company completed the Williston Basin Acquisition for a total adjusted purchase price of approximately $1.5 billion, consisting of approximately $788.2 million in cash and approximately $695.2 million in newly issued shares of Halcón preferred stock that automatically converted into 108.8 million shares of Halcón common stock (equivalent to a conversion price of approximately $7.45 per share of Halcón common stock), following stockholder approval on January 17, 2013 of such conversion and an amendment to Halcón's certificate of incorporation to increase the number of shares of common stock that Halcón is authorized to issue. The shares of preferred stock were issued to the Petro-Hunt Parties in a private placement pursuant to the exemptions from registration under Section 4(2) of the Securities Act of 1933, as amended.

On January 17, 2013, the Company received the results from the special stockholders' meeting authorizing and approving the issuance of 108.8 million shares of common stock upon the conversion of the convertible preferred stock issued to the Petro-Hunt Parties. Following the approval by the stockholders, on January 18, 2013, each outstanding share of the Company's preferred stock converted into 10,000 shares of its common stock at an effective conversion price of approximately $7.45 per share. No proceeds were received by the Company upon conversion of the preferred stock. No cash dividends were paid on the preferred stock since pursuant to the terms of the Certificate of Designation of the preferred stock, conversion occurred prior to April 6, 2013. On June 13, 2013, the Company filed a Certificate of Elimination with the Delaware Secretary of State eliminating all provisions of the Certificate of Designation.

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 Company filed a Certificate of Designations, Preferences, Rights and Limitations of 5.75% Series A Convertible Preferred Stock on June 17, 2013 (the Series A Designation). The net proceeds to the Company from the offering of the Series A Preferred Stock were approximately $335.5 million, after deducting the underwriting discount and offering expenses. The Company used the net proceeds from the offering to repay a portion of the 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, commencing on September 1, 2013. On September 3, 2013, the Company paid cumulative, declared dividends of $4.1 million by issuing 854,817 shares of common stock reflected as a non-cash dividend. As of September 30, 2013, cumulative, undeclared dividends on the Series A Preferred Stock amounted to approximately $1.7 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 as described below.

Each share of Series A Preferred Stock is convertible, at the holder's option at any time, initially into approximately 162.4431 shares of common stock of the Company (which is equivalent to an initial 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, approximately 56.0 million shares of common stock of the Company would be 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.

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.

On August 13, 2013, the Company completed the issuance and sale of 43.7 million shares of its common stock in an underwritten public offering. The shares of common stock 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 automatically effective on May 16, 2013. The net proceeds to the Company from the offering of common stock were approximately $215.2 million, after deducting the underwriting discount and estimated offering expenses. The Company used the net proceeds from the offering to repay a portion of the then outstanding borrowings under its Senior Credit Agreement.

On January 17, 2013, 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 333.3 million shares for a total of 670.0 million authorized shares of common stock.

On December 6, 2012, the Company completed the private placement of 41.9 million shares of common stock, par value $0.0001 per share, to CPP Investment Board PMI-2 Inc. (CPPIB), for gross proceeds of approximately $300.0 million, or $7.16 per share of common stock (the CPPIB Transaction). The net proceeds to the Company were $294.0 million following the payment of a $6.0 million capital commitment payment to CPPIB upon closing of the transaction. The shares of Halcón common stock were issued to CPPIB in a private placement pursuant to the exemptions from registration provided under Section 4(2) of the Securities Act. On September 27, 2013, the Company filed a shelf registration statement providing for the resale of certain of the shares of the Company's common stock held by CPPIB and its affiliates.

In early August 2012, in connection with the Merger and the East Texas Acquisition, the Company issued 51.3 million and 20.8 million shares of common stock, respectively. The shares were issued at closing of the transactions as a portion of the consideration of the purchase price. See Note 4, "Acquisitions and Divestitures," for additional discussion on the issuance of common stock in connection with these transactions.

On February 8, 2012 pursuant to the closing of the Recapitalization described in Note 2, "Recapitalization," the Company issued 73.3 million shares of the Company's common stock for a purchase price of $275.0 million. Costs incurred of $4.0 million were netted against the proceeds of the common stock and recorded accordingly. In addition, the Company amended its certificate of incorporation to increase the Company's authorized shares of common stock from 33.3 million shares to 336.7 million shares.

In February 2012, in conjunction with the issuance of the 2017 Notes, the Company issued the February 2012 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 pursuant to the Recapitalization described in Note 2, "Recapitalization." 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 entitle the holders to exercise the warrants in whole or in part at any time prior to the expiration date of February 8, 2017.

In August 2012, as part of the Merger, the Company assumed outstanding GeoResources stock warrants. At the date of the Merger 0.6 million warrants were outstanding and converted to 1.2 million Halcón warrants (the August 2012 Warrants). Each GeoResources warrant was converted into an August 2012 Warrant to acquire one share of Halcón common stock (Share Portion) at an exercise price of $8.40 per share of common stock and the right to receive $20 in cash per equivalent assumed share (Cash Portion) at an exercise price of $0.82 per $1.00 received. The August 2012 Warrants contain substantially the same terms of the original GeoResources warrants with adjustments to the exercise price and addition of the Cash Portion to reflect the impact of the consideration per share from the Merger. These adjustments convert the terms to fundamentally equal what the warrant holders would have received had the warrants been exercised immediately prior to the close of the Merger. Under the terms of the August 2012 Warrants, the warrant holder must exercise the Share Portion and the Cash Portion in tandem. The August 2012 Warrants expired on June 9, 2013. The August 2012 Warrants were reflected as a current liability in the consolidated balance sheets at December 31, 2012 and were recorded at fair value. During the nine months ended September 30, 2013, the Company recorded a gain of $1.6 million for the expiration of the warrants. Changes in fair value and the gain upon expiration were recognized in "Interest expense and other" in the unaudited condensed consolidated statements of operations.

On May 8, 2006, the Company's stockholders first approved its 2006 Long-Term Incentive Plan (the Plan). The Company reserved a maximum of 0.8 million shares of its common stock for issuances under the Plan. On May 8, 2008, the Plan was amended to increase the maximum authorized number of shares to be issued under the Plan from 0.8 million to 2.0 million. On May 3, 2010, the Plan was amended to increase the maximum authorized number of shares to be issued under the Plan from 2.0 million to 2.5 million. On February 8, 2012, as part of the Recapitalization described in Note 2, "Recapitalization," the Plan was amended to increase the maximum authorized number of shares to be issued under the Plan from 2.5 million to 3.7 million. On May 17, 2012, shareholders approved an amendment and restatement of the Plan to (i) increase the maximum number of shares to be issued under the Plan from 3.7 million to 11.5 million; (ii) extend the effectiveness of the Plan for ten years from the date of approval; and (iii) amend various other provisions of the Plan. On May 23, 2013, shareholders approved an increase in authorized shares under the Plan from 11.5 million to 41.5 million. As of September 30, 2013 and December 31, 2012, a maximum of 25.6 million and 4.4 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 Topic 718. The guidance requires all share-based payments to

employees and directors, including grants of stock options and restricted stock, to be recognized in the financial statements based on their fair values.

For the three and nine months ended September 30, 2013, the Company recognized $5.0 million and $12.0 million, respectively, of share-based compensation expense as a component of "General and administrative" on the unaudited condensed consolidated statements of operations. For the three and nine months ended September 30, 2012, the Company recognized $1.4 million and $6.0 million, respectively, of share-based compensation expense.

During the nine months ended September 30, 2013, the Company granted stock options under the Plan covering 6.1 million shares of common stock to employees of the Company. The stock options have exercise prices ranging from $4.43 to $8.23 with a weighted average exercise price of $7.07. 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, 2013, the Company had $15.7 million of unrecognized compensation expense related to non-vested stock options to be recognized over a weighted-average period of 1.3 years.

During the nine months ended September 30, 2012, the Company granted stock options covering approximately 2.0 million shares of common stock to employees of the Company. The stock options have exercise prices ranging from $6.26 to $11.55 with a weighted average price of $9.10. These awards 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, 2012, the Company had $5.9 million of unrecognized compensation expense related to non-vested stock options to be recognized over a weighted-average period of 1.7 years.

During the nine months ended September 30, 2013, the Company granted 3.3 million shares of restricted stock under the Plan to directors and employees of the Company. These restricted shares were granted at prices ranging from $4.43 to $7.65 with a weighted average price of $6.91. 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, 2013, the Company had $14.1 million of unrecognized compensation expense related to non-vested restricted stock awards to be recognized over a weighted-average period of 1.3 years.

During the nine months ended September 30, 2012, the Company granted 0.3 million shares of restricted stock under the Plan to directors and employees of the Company. These restricted shares were granted at a prices ranging from $6.92 to $10.13 with a weighted average price of $9.29. 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, 2012, the Company had $2.0 million of unrecognized compensation expense related to non-vested restricted stock awards to be recognized over a weighted-average period of 2.0 years.

During the nine months ended September 30, 2012, the Company incurred compensation expense of $2.6 million primarily from the accelerated vesting of all unvested employee restricted stock shares

due to the change in control in the Company resulting from the Recapitalization as described in Note 2, "Recapitalization."

During February 2012, the Company accelerated vesting and exercise of all unvested stock appreciation rights under the Plan (SARs) that were granted in May 2011, due to the change in control of the Company resulting from the Recapitalization described in Note 2, "Recapitalization." The Company settled the SARs in cash, resulting in $2.2 million of share-based compensation expense recognized for the nine months ended September 30, 2012. The realized compensation expense was partially offset by the reversal of $0.8 million of unrealized losses recorded at December 31, 2011.

As discussed above, during the nine months ended September 30, 2013, the Company granted 3.3 million shares of restricted stock under the Plan to directors and employees of the Company of which 1.2 million shares were issued out of treasury stock. In addition, the Company retired 0.4 million shares from treasury stock representing shares that were repurchased for taxes tendered upon vesting of stock based compensation awards in prior years. As of September 30, 2013, the Company had no issued shares held in treasury.

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.

The Company estimates its annual effective income tax rate in recording its quarterly provision for income taxes in the various jurisdictions in which the Company operates. Statutory tax rate changes and other significant or unusual items are recognized as discrete items in the quarter in which they occur. At September 30, 2013 and December 31, 2012, the Company analyzed and made no adjustment to the valuation allowance.

The Company recorded a tax benefit of $333.9 million on a pre-tax loss of $1.1 billion for the nine months ended September 30, 2013. For the nine months ended September 30, 2012, the Company recorded a tax provision of $1.2 million on a pre-tax loss of $44.7 million. The effective tax rate for the nine months ended September 30, 2013 was 29.1% compared to 2.6% for the nine months ended September 30, 2012. The change in effective tax rate is primarily due to the pre-tax loss in the current year and the impact of federal income tax limitations on the deductibility of the third quarter 2013 goodwill impairment and interest expense on the 2017 Note issued as part of the Recapitalization in February 2012.

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,

	2013			2012			2013			2012
	(In thousands, except per share amounts)
Basic:
Net income (loss) available to common stockholders	$	(859,897	)	$	(20,181	)	$	(818,060	)	$	(134,289	)

Weighted average basic number of common shares outstanding		392,726			191,846			368,696			132,460

Basic net income (loss) per share of common stock	$	(2.19	)	$	(0.11	)	$	(2.22	)	$	(1.01	)

Diluted:
Net income (loss) available to common stockholders	$	(859,897	)	$	(20,181	)	$	(818,060	)	$	(134,289	)

Weighted average basic number of common shares outstanding		392,726			191,846			368,696			132,460
Common stock equivalent shares representing shares issuable upon:
Exercise of stock options		Anti-dilutive			Anti-dilutive			Anti-dilutive			Anti-dilutive
Exercise of February 2012 Warrants		Anti-dilutive			Anti-dilutive			Anti-dilutive			Anti-dilutive
Exercise of August 2012 Warrants		—			Anti-dilutive			Anti-dilutive			Anti-dilutive
Vesting of restricted shares		Anti-dilutive			Anti-dilutive			Anti-dilutive			Anti-dilutive
Conversion of 2017 Notes		Anti-dilutive			Anti-dilutive			Anti-dilutive			Anti-dilutive
Conversion of preferred stock		—			Anti-dilutive			Anti-dilutive			Anti-dilutive
Conversion of Series A Preferred Stock		Anti-dilutive			—			Anti-dilutive			—

Weighted average diluted number of common shares outstanding		392,726			191,846			368,696			132,460

Diluted net income (loss) per share of common stock	$	(2.19	)	$	(0.11	)	$	(2.22	)	$	(1.01	)

Common stock equivalents, including stock options, warrants, restricted shares, convertible debt, and preferred stock, totaling 170.9 million and 142.4 million shares for the three and nine months ended September 30, 2013, respectively, were not included in the computation of diluted earnings per share of common stock because the effect would have been anti-dilutive due to the net losses. Common stock equivalents of stock options, preferred stock, warrants and the 2017 Note totaling 78.8 million and 77.1 million shares for the three and nine months ended September 30, 2012, respectively, were not included in the computations of diluted earnings per share of common stock because the effect would have been anti-dilutive due to the net losses.

	September 30, 2013		December 31, 2012

	(In thousands)
Accounts receivable:
Oil, natural gas and natural gas liquids revenues	$	167,267	$	143,794
Joint interest accounts		118,090		113,671
Affiliated partnerships		138		475
Other		6,783		4,869

	$	292,278	$	262,809

Prepaids and other:
Prepaids	$	5,163	$	3,690
Income tax receivable		10,919		2,993
Other		60		8

	$	16,142	$	6,691

Other noncurrent assets:
Deposits for acquisitions of oil and natural gas properties	$	10,908	$	—
Other		274		934

	$	11,182	$	934

Accounts payable and accrued liabilities:
Trade payables	$	143,240	$	147,679
Accrued oil and natural gas capital costs		313,739		282,245
Revenues and royalties payable		136,549		91,761
Accrued interest expense		67,401		45,201
Accrued employee compensation		17,811		12,321
Drilling advances from partners		16,189		8,840
Accounts payable to affiliated partnerships		120		822
Other		3		1,682

	$	695,052	$	590,551

During the third quarter of 2013, the Company entered into three separate purchase and sale agreements with unrelated parties to divest certain distinct non-core conventional assets located throughout the United States for total consideration of approximately $302 million, two of which have closed as of the date of this report and the third is expected to close before year-end 2013. The transactions and consideration are subject to customary closing conditions and adjustments, with an effective date of July 1, 2013. Proceeds from the sales will be recorded as a reduction to the carrying value of the Company's full cost pool with no gain or loss recorded. Upon the closing of all three divestitures, the Company expects the borrowing base under the Senior Credit Agreement to be reduced from $850.0 million to $800.0 million.

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, 2013 and 2012 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 included in our Annual Report on Form 10-K for the year ended December 31, 2012.

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.

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. Historically, our producing properties have been located in basins with long histories of oil and natural gas operations. During 2012, we focused our efforts on the acquisition of unevaluated leasehold and producing properties in selected prospect areas. We have acquired acreage, and may acquire additional acreage, in several onshore liquids-rich basins in the United States. We now have an extensive drilling inventory in multiple basins that we believe allows for multiple years of profitable production growth and provides us with broad flexibility to direct our capital resources to projects with the greatest potential returns.

Our average daily oil and natural gas production increased 384% in the first nine months of 2013 compared to the same period in the prior year. During the first nine months of 2013, we averaged 31,007 barrels of oil equivalent (Boe) per day compared to average daily production of 6,401 Boe per day during the first nine months of 2012. The increase in production compared to the prior year period was driven primarily by operated drilling results and the acquisitions of GeoResources, the East Texas Assets and the Williston Basin Assets. The acquisitions of GeoResources, the East Texas Assets and the Williston Basin Assets combined to contribute approximately 24,600 Boe per day of the increase. During the first nine months of 2013, we participated in the drilling of 213 gross (87.6 net) wells of which 210 gross (84.6 net) wells were completed and capable of production, and 3 gross (3.0 net) wells were dry holes.

Our 2013 budget for drilling and completion capital expenditures has been increased from an initial budget of approximately $1.2 billion to approximately $1.4 billion. While this amount represents the vast majority of our expected capital expenditures in 2013, we have and will continue to incur additional capital expenditures associated with ongoing leasing efforts, transportation, infrastructure, and seismic and other expenditures. Our drilling and completion budget for 2013 is based on our current view of market conditions and current business plans, and is subject to change.

During the third quarter of 2013, we entered into three separate purchase and sale agreements with unrelated parties to divest certain distinct non-core conventional assets located throughout the United States for total consideration of approximately $302 million, two of which have closed as of the date of this report and the third is expected to close before year-end 2013. The transactions and consideration are subject to customary closing conditions and adjustments, with an effective date of July 1, 2013. Upon the closing of all three divestitures, we expect the borrowing base under our Senior Credit Agreement to be reduced from $850.0 million to $800.0 million.

On August 13, 2013, we issued $400 million aggregate principal amount of 9.25% senior notes due 2022 issued at par (the 2022 Notes). The net proceeds from the offering were approximately $392.1 million after deducting the commissions and offering expenses and were used to repay a portion of the then outstanding borrowings on our Senior Credit Agreement. See Item 1. Condensed Consolidated Financial Statements (Unaudited)—Note 6, "Long-Term Debt" for additional information on the 2022 Notes.

On August 13, 2013, we also completed the issuance and sale of 43.7 million shares of common stock in an underwritten public offering. The net proceeds from the offering of common stock were approximately $215.2 million, after deducting the underwriting discount and estimated offering expenses. We used the net proceeds from the offering to repay a portion of the then outstanding borrowings on our Senior Credit Agreement. See Item 1. Condensed Consolidated Financial Statements (Unaudited)—Note 11, "Preferred Stock and Stockholders' Equity" for additional information on the common stock offering.

On July 19, 2013, we completed the sale of our interest in Eagle Ford assets in Fayette and Gonzales Counties, Texas, previously acquired as part of the Merger, to private buyers for proceeds of approximately $147.9 million, before post-closing adjustments. The transaction had an effective date of January 1, 2013. Proceeds from the sale were recorded as a reduction to the carrying value of our full cost pool with no gain or loss recorded.

On June 18, 2013, we completed our offering of 345,000 shares of 5.75% Series A Convertible Perpetual Preferred Stock (the Series A Preferred Stock) at a public offering price of $1,000 per share. The net proceeds to us from the offering of the Series A Preferred Stock were approximately $335.5 million, after deducting the underwriting discount and offering expenses. We used the net proceeds from the offering to repay a portion of the outstanding borrowings under our Senior Credit Agreement. Holders of the Series A Preferred Stock are entitled to receive, when, as and if declared by our Board of Directors, cumulative dividends at the rate of 5.75% per annum (the dividend rate) on the $1,000 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 shares of common stock or a combination thereof, and are payable on March 1, June 1, September 1 and December 1 of each year, commencing on September 1, 2013. See Item 1. Condensed Consolidated Financial Statements (Unaudited)—Note 11, "Preferred Stock and Stockholders' Equity" for additional information on the Series A Preferred Stock.

On October 31, 2013, we entered into the Sixth Amendment to the Senior Credit Agreement (the Sixth Amendment). The Sixth Amendment increases our borrowing base to $850.0 million with an automatic reduction to $800.0 million upon the closing of all three non-core divestitures discussed in Note 15, "Subsequent Event." Additionally, the Sixth Amendment provides for EBITDA (as defined in the Senior Credit Agreement) to be annualized for the next three fiscal quarters for purposes of measuring compliance with the interest coverage test. Specifically, (i) for the fiscal quarter ended December 31, 2013, the Interest Coverage Ratio shall be calculated by utilizing EBITDA for the three month period then ended multiplied by 4; (ii) for the fiscal quarter ended March 31, 2014, the Interest Coverage Ratio shall be calculated by utilizing EBITDA for the six month period then ended multiplied by 2; and (iii) for the fiscal quarter ended June 30, 2014, the Interest Coverage Ratio shall be calculated by utilizing EBITDA for the nine month period then ended multiplied by ⁴/3.

On June 11, 2013, we entered into the Fifth Amendment to the Senior Credit Agreement (the Fifth Amendment). The Fifth Amendment permits, among other things, us to pay cash dividends to holders of our preferred capital stock.

On May 8, 2013, we entered into the Fourth Amendment to the Senior Credit Agreement (the Fourth Amendment). The Fourth Amendment provides for modifications to the calculation that measures compliance with the interest coverage test. The provisions of the Fourth Amendment are superseded by the Sixth Amendment discussed herein.

On April 26, 2013, we entered into the Third Amendment to our Senior Credit Agreement (the Third Amendment) by and among us, as borrower, JPMorgan Chase Bank, N.A., as administrative agent, and the other lenders signatory thereto, which amends the Senior Credit Agreement in order to provide, among other things, additional flexibility under certain affirmative and negative covenants.

On January 25, 2013, we entered into the Second Amendment to our Senior Credit Agreement (the Second Amendment) by and among us, as borrower, JPMorgan Chase Bank, N.A., as administrative agent, and the other lenders signatory thereto. The Second Amendment amends the Senior Credit Agreement with respect to our ability to enter into certain commodity hedging agreements.

See Item 1. Condensed Consolidated Financial Statements (Unaudited)—Note 6, "Long-Term Debt" for additional information on the amendments to our Senior Credit Agreement.

On January 14, 2013, we issued an additional $600 million aggregate principal amount of our 8.875% senior notes due 2021 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 outstanding borrowings under our Senior Credit Agreement and for general corporate purposes, including funding a portion of our 2013 capital expenditures program. These notes were issued as "additional notes" under the indenture governing our 2021 Notes and pursuant to which we had previously issued $750 million aggregate principal amount of 2021 Notes in November 2012, and under the indenture are treated as a single series with substantially identical terms as the 2021 Notes previously issued. See Item 1. Condensed Consolidated Financial Statements (Unaudited)—Note 6, "Long-Term Debt" for additional information on the 2021 Notes.

During 2013, we shifted the primary focus of our capital program from acquiring leasehold and producing properties to drilling and completion activities. We are currently focused on developing our core areas which include the Bakken / Three Forks formations in North Dakota, the Eagle Ford formation in East Texas, and the Utica / Point Pleasant formations in Ohio and Pennsylvania. In addition to our ongoing drilling and completion activities we continue to acquire leasehold in our core areas and select other exploratory areas we believe are prospective for oil and liquids-rich hydrocarbons. During the first nine months of 2013, we invested $1.8 billion in oil and natural gas capital expenditures, including drilling and completions and other capital costs.

Our near-term capital spending requirements are expected to be funded with cash flows from operations, proceeds from potential non-core asset dispositions, proceeds from potential capital market transactions and borrowings under our Senior Credit Agreement, which has a current borrowing base of $850.0 million that was affirmed in the redetermination that occurred on October 31, 2013. Should all three of non-core divestitures successfully close, we expect the borrowing base to be reduced to $800.0 million. See Item 1. Condensed Consolidated Financial Statements (Unaudited)—Note 15, "Subsequent Event" for more details on the non-core divestitures. 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 our oil and natural gas properties, reserves, other indebtedness and other relevant factors. 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 unsecured 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 minimum coverage of interest expenses (as defined in the Senior Credit Agreement) of not less than 2.5 to 1.0. We are 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 unsecured 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 the amount of such additional indebtedness is not more than the greater of a fixed sum of $750 million or 30% of our adjusted consolidated net tangible assets (as defined in our indentures), which is determined primarily using discounted future net revenues from proved oil and natural gas reserves as of the end of each year. At September 30, 2013, under our then effective borrowing base of $710.0 million, we had $232.0 million of indebtedness outstanding, $1.2 million of letters of credit outstanding and $476.8 million of borrowing capacity available under the Senior Credit Agreement.

We strive to maintain financial flexibility while continuing our aggressive drilling plans and evaluating potential acquisitions, and will therefore likely continue to access capital markets (if 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. If oil and natural gas prices decline for a sustained period of time, our ability to fund our capital expenditures, complete acquisitions, reduce debt, and meet our financial obligations may be materially impacted.

Our future capital resources and liquidity depend, in part, on our success in developing our leasehold interests, growing 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 successes.

Our primary source of cash for the nine months ended September 30, 2013 and 2012 was from financing activities. In the first nine months of 2013, proceeds from the 2022 Notes, the additional 2021 Notes, the issuance of common stock and the issuance of our Series A Preferred Stock were the primary drivers of the net cash provided by financing activities. The increase in cash received from operations, coupled with the cash from financing activities, were offset by cash used in investing activities to fund our drilling program and acquire additional leasehold interests. Operating cash flow increases were substantially driven by the significant increase in production volumes namely in our

Bakken program, as compared to the nine months ended September 30, 2012 and, to a lesser extent, higher commodity prices. Fluctuations in commodity prices and our overall cash flow may result in an increase or decrease in our future capital expenditures. Prices for oil and natural gas have historically been subject to seasonal fluctuations characterized by peak demand and higher prices in the winter heating season; however, the impact of other risks and uncertainties have influenced prices throughout recent years. See Results of Operations below 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, 2013 was $391.6 million as compared to cash provided by operating activities for the nine months ended September 30, 2012 of $1.9 million.

The $391.6 million of operating cash flows for the nine months ended September 30, 2013, primarily reflects the impact of increased production from our acquisitions and developmental drilling activities which drove a significant increase in revenues, as compared to the prior year period, and outpaced related production costs and higher general and administrative expenses associated with additional personnel and infrastructure in support of our expanding business.

Investing Activities. The primary driver of cash used in investing activities is capital spending, specifically drilling and completions coupled with the acquisition of unevaluated leasehold acreage in our target areas. Net cash used in investing activities was approximately $1.8 billion and $1.6 billion for the nine months ended September 30, 2013 and 2012, respectively.

During the first nine months of 2013, we incurred $1.8 billion on oil and natural gas capital expenditures. We participated in the drilling of 213 gross (87.6 net) wells of which 210 gross (84.6 net) wells were completed and capable of production, and 3 gross (3.0 net) wells were dry holes. We spent an additional $120.1 million on other operating property and equipment capital expenditures, of which $104.5 million pertained to pipelines and related infrastructure projects, and the remainder was spent on leasehold improvements, the purchase of an aircraft and automobiles, and computers and software primarily in our corporate office in Houston, Texas. Proceeds from sales of oil and gas properties were approximately $160.3 million primarily attributable to the July 2013 sale of Eagle Ford Shale assets located in Fayette and Gonzales Counties, Texas.

During the first nine months of 2012, we incurred cash expenditures of $579.5 million, net of cash acquired, on the Merger with GeoResources, $296.1 million on the acquisition of the East Texas Assets, and $716.1 million on oil and natural gas capital expenditures, which included acquisitions of unevaluated leasehold properties, seismic and exploratory drilling. We participated in the drilling of 82 gross (54.5 net) wells of which 40 gross (35 net) wells were completed and capable of production, 40 gross (17.6 net) wells were drilling or waiting on completion and two gross (1.9 net) wells were dry holes. We also drilled and completed 4 gross (4 net) salt water disposal wells and completed 1 gross (1 net) well that we did not drill during the first nine months of 2012. We spent an additional $18.1 million on other operating property and equipment capital expenditures; of which $12.1 million was spent on pipelines and related infrastructure projects and the remainder was spent on leasehold improvements, computers and software primarily in our corporate office in Houston, Texas.

Financing Activities. Net cash flows provided by financing activities were $1.4 billion and $1.6 billion for the nine months ended September 30, 2013 and 2012, respectively. The primary drivers of cash provided by financing activities for the nine months ended September 30, 2013, were proceeds, net of issuance costs, from the issuance of the 2021 and 2022 Notes, the issuance of 43.7 million shares of common stock, and the issuance of Series A Preferred Stock. Proceeds from these issuances were primarily used to repay borrowings under our Senior Credit Agreement.

On August 13, 2013, we completed the issuance of $400 million aggregate principal amount of our 2022 Notes. The net proceeds to us from the offering were approximately $392.1 million after deducting commissions and offering expenses and were used to repay a portion of the then outstanding borrowings under our Senior Credit Agreement.

On August 13, 2013, we also completed our offering of 43.7 million shares of common stock in an underwritten public offering. The net proceeds from the offering of our common stock were approximately $215.2 million, after deducting the underwriting discount and estimated offering expenses. We used the net proceeds from the offering to repay a portion of the then outstanding borrowings on our Senior Credit Agreement.

On June 18, 2013, we completed our offering of 345,000 shares of the Series A Preferred Stock at a public offering price of $1,000 per share. The net proceeds to us from the offering of the Series A Preferred Stock were approximately $335.5 million, after deducting the underwriting discount and offering expenses. We used the net proceeds from the offering to repay a portion of the then outstanding borrowings under our Senior Credit Agreement.

On January 14, 2013, we completed the issuance of an additional $600 million aggregate principal amount of our 2021 Notes at a price to the initial purchasers of 105% of par. The net proceeds from the sale of the additional 2021 Notes were approximately $619.5 million (after deducting offering fees and expenses). The net proceeds from this offering were used to repay all of the then outstanding borrowings under our Senior Credit Agreement and for general corporate purposes, including funding a portion of our 2013 capital expenditures program.

During the first nine months of 2012, as discussed in Item 1. Condensed Consolidated Financial Statements (Unaudited)—Note 2, "Recapitalization," HALRES recapitalized us with a $550.0 million investment structured as the purchase of $275.0 million in new common stock, a $275.0 million five-year 8.0% convertible note and warrants for the purchase of an additional 36.7 million shares of our common stock at an exercise price of $4.50 per share. The convertible note provided $231.4 million cash flow from borrowings and $43.6 million cash flow from warrants issued. Proceeds from the Recapitalization were used to repay the $208.0 million of borrowings under previous credit facilities. In July of 2012, we issued $750 million aggregate principal amount of our 2020 Notes issued at 98.646% of par. 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 and the East Texas Acquisition. In addition, we received $400.0 million, subject to certain adjustments, from the private placement sale of convertible Preferred Stock during March 2012.

All restricted stock awards were vested as a result of the change in control in February 2012. For the nine months ended September 30, 2012, we repurchased $2.1 million in common stock from participants under our 2006 Long-Term Incentive Plan to net settle the related withholding tax liability.

We lease corporate office space in Houston, Texas; Tulsa, Oklahoma; Denver, Colorado; and Williston, North Dakota as well as a number of other field office locations. Rent expense was approximately $6.8 million and $2.2 million for the nine months ended September 30, 2013 and 2012, respectively. 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 2015. Early termination of the drilling rig commitments would result in termination penalties approximating $35.5 million, which would be in lieu of the remaining $57.4 million of drilling rig commitments as of September 30, 2013. As of September 30, 2013, the amount of commitments under office and equipment lease agreements is consistent with the levels at December 31, 2012 disclosed in our Annual Report on Form 10-K, approximating $67.6 million in the aggregate, and containing various expiration dates through 2024.

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 year ended December 31, 2012.

We reported a net loss of $854.8 million and $20.2 million for the three months ended September 30, 2013 and 2012, 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)	2013			2012			Change
Net income (loss)	$	(854,827	)	$	(20,181	)	$	(834,646	)
Operating revenues:
Oil		288,850			65,670			223,180
Natural gas		7,457			3,918			3,539
Natural gas liquids		7,894			3,230			4,664
Other		806			489			317
Operating expenses:
Production:
Lease operating		37,539			14,197			23,342
Workover and other		2,029			1,123			906
Taxes other than income		26,613			5,814			20,799
Gathering and other		3,766			167			3,599
Restructuring		—			725			(725	)
General and administrative:
General and administrative		28,743			31,722			(2,979	)
Share-based compensation		5,019			1,402			3,617
Depletion, depreciation and accretion:
Depletion—Full cost		139,852			21,596			118,256
Depreciation—Other		2,236			535			1,701
Accretion expense		1,003			595			408
Full cost ceiling impairment		909,098			—			909,098
Other operating property and equipment impairment		67,254			—			67,254
Goodwill impairment		228,875			—			228,875
Other income (expenses):
Net gain (loss) on derivative contracts		(54,427	)		(9,575	)		(44,852	)
Interest expense and other, net		(13,663	)		(5,074	)		(8,589	)
Income tax (provision) benefit		360,283			(963	)		361,246
Production:
Oil—MBbls		2,885			704			2,181
Natural Gas—Mmcf		2,195			1,441			754
Natural gas liquids—MBbls		218			85			133
Total MBoe⁽¹⁾		3,469			1,029			2,440
Average daily production—Boe⁽¹⁾		37,707			11,185			26,522
*Average price per unit⁽²⁾***:
Oil price—Bbl	$	100.12		$	93.28		$	6.84
Natural gas price—Mcf		3.40			2.72			0.68
Natural gas liquids price—Bbl		36.21			38.00			(1.79	)
Total per Boe⁽¹⁾		87.69			70.77			16.92
Average cost per Boe:
Production:
Lease operating	$	10.82		$	13.80		$	(2.98	)
Workover and other		0.58			1.09			(0.51	)
Taxes other than income		7.67			5.65			2.02
Gathering and other		1.09			0.16			0.93
Restructuring		—			0.70			(0.70	)
General and administrative:
General and administrative		8.29			30.83			(22.54	)
Share-based compensation		1.45			1.36			0.09
Depletion		40.31			20.99			19.32

For the three months ended September 30, 2013, oil, natural gas and natural gas liquids revenues increased $231.4 million from the same period in 2012. The increase was primarily due to an increase in production volumes resulting from the Merger, the East Texas Acquisition and the Williston Basin Acquisition and our continued development within these areas, which collectively accounted for an increase of approximately 26,600 Boe per day in production and $228.0 million of incremental revenues. Realized average prices per Boe increased $16.92 to $87.69 per Boe.

Lease operating expenses increased $23.3 million for the three months ended September 30, 2013, primarily due to $17.9 million of costs incurred on acquired properties and an increase in production within these areas as we continue to carry out our development plan. Lease operating expenses were $10.82 per Boe for the three months ended September 30, 2013, compared to $13.80 per Boe for the same period in 2012. The decrease per Boe is largely due to a lower ratio of expense to production volumes on acquired properties.

Workover expenses increased $0.9 million for the three months ended September 30, 2013 compared to the same period in 2012 primarily due to $1.0 million of expenses associated with acquired properties and an increase in activity in these areas. This increase was partially offset by decreased workover expenses on our existing properties.

Taxes other than income increased $20.8 million for the three months ended September 30, 2013 as compared to the same period in 2012 primarily due to $18.5 million of taxes associated with acquired properties and the increase in production within these areas as we continue to carry out our development plan. 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 $7.67 per Boe and $5.65 per Boe for the three months ended September 30, 2013 and 2012, respectively.

Gathering and other expenses for the three months ended September 30, 2013 and 2012 were $3.8 million and $0.2 million, respectively. In 2013, approximately $1.2 million of these expenses were attributable to midstream infrastructure that we developed in our Woodbine and Utica / Point Pleasant operating areas and approximately $2.6 million relates to gathering and other fees paid on our oil and natural gas production.

In March 2012, we announced our intention to close our Plano, Texas office and began the process of relocating key administrative functions to our corporate headquarters in Houston, Texas (the Restructuring). As part of the Restructuring, we offered certain severance and retention benefits to affected employees. As of May 2013, the requisite service period had ended and all severance and retention related payments had been made.

General and administrative expense for the three months ended September 30, 2013 decreased $3.0 million to $28.7 million as compared to the same period in 2012. The decrease in general and administrative expenses results from acquisition-related expenses incurred in 2012 related to the Merger. The decrease in general and administrative expenses was partially offset by increases in payroll and related employee benefit costs of $5.7 million, office related expenses of $2.0 million and professional fees of $5.2 million, in support of our expanding business base and increased corporate activities subsequent to the Recapitalization.

Share-based compensation expense for the three months ended September 30, 2013 was $5.0 million, an increase of $3.6 million compared to the same period in 2012. The increase in share-based compensation expense results from awards to employees and directors driven by an increase in employee headcount and the size of our board of directors since the prior year period.

of the period for the evaluated properties. Depletion expense increased $118.3 million to $139.9 million for the three months ended September 30, 2013 compared to the same period in 2012, primarily due to a higher depletion rate per Boe and increased production. On a per unit basis, depletion expense was $40.31 per Boe for the three months ended September 30, 2013 compared to $20.99 per Boe for the three months ended September 30, 2012. The increase in depletion expense and the depletion rate per Boe is primarily due to the increase in production volumes and reserves as a result of the Merger, the East Texas Acquisition and the Williston Basin Acquisitions during the third and fourth quarters of 2012. In addition, the transfer of $655.7 million of unevaluated property costs to the full cost pool during the third quarter of 2013 increased the capitalized costs of evaluated properties and contributed to the higher depletion expense on both an absolute dollar and per Boe basis.

Accretion expense is a function of changes in the discounted asset retirement obligation liability from period to period. We recorded accretion expense of $1.0 million for the three months ended September 30, 2013, compared to $0.6 million for the same period in 2012.

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. At September 30, 2013, our costs exceeded our ceiling limitation by $909.1 million, resulting in a write-down of our oil and natural gas properties before income taxes. During the three months ended September 30, 2013, we transferred $655.7 million of unevaluated property costs to the full cost pool primarily related to Woodbine assets in East Texas where capital has been reallocated to El Halcón, and certain Utica/Point Pleasant assets in Northwest Pennsylvania related to non-economical drilling results obtained in the third quarter of 2013. The combined impact of less favorable oil price differentials adversely affecting proved reserve values and the aforementioned transfers of unevaluated properties to the full cost pool contributed to the ceiling impairment. Changes in 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.

We review our gas gathering systems and equipment and other operating assets for impairment in accordance with ASC 360. For the three months ended September 30, 2013, we recorded a non-cash impairment charge of $67.3 million. The impairment relates to our gross investments of $68.3 million in gas gathering infrastructure that will not be economically recoverable due to our shift in exploration, drilling and developmental plans from the Woodbine area to El Halcón during the third quarter of 2013.

During the third quarter of 2013, we performed our annual goodwill impairment test, and based on this review; we recorded a non-cash impairment charge of $228.9 million to reduce the carrying value of goodwill to zero. In the first step of the goodwill impairment test, we determined that the fair value of our reporting unit was less than the carrying amount, including goodwill, primarily due to pricing deterioration in the NYMEX forward pricing curve coupled with less favorable oil price differentials in our core areas, both factors which adversely impacted the fair value of our proved reserves. Therefore, we performed the second step of the goodwill impairment test, which led us to conclude that there would be no remaining implied fair value attributable to goodwill.

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, 2013, we had an $8.9 million derivative asset, $3.2 million of which was classified as current, and we had a $31.5 million derivative liability, $30.4 million of which was classified as current. We recorded a net derivative loss of $54.4 million ($38.1 million net unrealized loss and $16.3 million net realized loss on settled contracts and premium costs) for the three months ended September 30, 2013 compared to a net derivative loss of $9.6 million ($11.8 million net unrealized loss and $2.2 million net realized gain), in the same period in 2012.

Interest expense increased $8.6 million for the three months ended September 30, 2013 from the same period in 2012. Capitalized interest for the three months ended September 30, 2013 and 2012 was $53.2 million and $19.5 million, respectively. This increase in capitalized interest was driven by increases in our unevaluated properties since September 30, 2012. Interest expense subject to capitalization increased to $67.4 million in the three months ended September 30, 2013 from $24.3 million in the comparable prior year period. The increase in interest subject to capitalization is attributed to the issuance of our additional 2021 Notes and the 2022 Notes.

We recorded an income tax benefit of $360.3 million for the three months ended September 30, 2013 due to our pre-tax loss of $1.2 billion compared to an income tax provision of $1.0 million due to our pre-tax loss of $19.2 million in the prior year. The effective tax rate for the three months ended September 30, 2013 is 29.7% compared to 5.0% for the three months ended September 30, 2012. The change in effective tax rate is primarily due to the pre-tax loss in the current period and the impact of federal income tax limitations on the deductibility of the goodwill impairment and interest expense on the 2017 Note issued as part of the Recapitalization in February 2012.

We reported a net loss of $812.3 million and $45.8 million for the nine months ended September 30, 2013 and 2012, 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)	2013			2012			Change
Net income (loss)	$	(812,274	)	$	(45,844	)	$	(766,430	)
Operating revenues:
Oil		672,167			109,050			563,117
Natural gas		19,971			6,875			13,096
Natural gas liquids		15,976			7,080			8,896
Other		2,090			560			1,530
Operating expenses:
Production:
Lease operating		94,676			30,113			64,563
Workover and other		4,276			2,384			1,892
Taxes other than income		62,616			9,648			52,968
Gathering and other		6,901			274			6,627
Restructuring		507			1,732			(1,225	)
General and administrative:
General and administrative		86,891			60,293			26,598
Share-based compensation		11,994			6,034			5,960
Depletion, depreciation and accretion:
Depletion—Full cost		312,658			32,141			280,517
Depreciation—Other		4,778			1,096			3,682
Accretion expense		2,828			1,424			1,404
Full cost ceiling impairment		909,098			—			909,098
Other operating property and equipment impairment		67,254			—			67,254
Goodwill impairment		228,875			—			228,875
Other income (expenses):
Net gain (loss) on derivative contracts		(38,749	)		(849	)		(37,900	)
Interest expense and other, net		(24,245	)		(22,250	)		(1,995	)
Income tax (provision) benefit		333,868			(1,171	)		335,039
Production:
Oil—MBbls		7,028			1,151			5,877
Natural Gas—Mmcf		5,887			2,640			3,247
Natural gas liquids—MBbls		456			163			293
Total MBoe⁽¹⁾		8,465			1,754			6,711
Average daily production—Boe⁽¹⁾		31,007			6,401			24,606
*Average price per unit⁽²⁾***:
Oil price—Bbl	$	95.64		$	94.74		$	0.90
Natural gas price—Mcf		3.39			2.60			0.79
Natural gas liquids price—Bbl		35.04			43.44			(8.40	)
Total per Boe⁽¹⁾		83.65			70.13			13.52
Average cost per Boe:
Production:
Lease operating	$	11.18		$	17.17		$	(5.99	)
Workover and other		0.51			1.36			(0.85	)
Taxes other than income		7.40			5.50			1.90
Gathering and other		0.82			0.16			0.66
Restructuring		0.06			0.99			(0.93	)
General and administrative:
General and administrative		10.26			34.37			(24.11	)
Share-based compensation		1.42			3.44			(2.02	)
Depletion		36.94			18.32			18.62

For the nine months ended September 30, 2013, oil, natural gas and natural gas liquids revenues increased $585.1 million from the same period in 2012. The increase was primarily due to an increase in production volumes resulting from the Merger, the East Texas Acquisition and the Williston Basin Acquisition and our continued development within these areas, which collectively accounted for an increase of approximately 24,600 Boe per day in production and $581.4 million of incremental revenues. Realized average prices per Boe increased $13.52 to $83.65 per Boe.

Lease operating expenses increased $64.6 million for the nine months ended September 30, 2013, primarily due to $56.7 million of costs incurred on acquired properties and an increase in production within these areas as we continue to carry out our development plan. The remaining increases are due to higher power costs, service costs and repairs. Lease operating expenses were $11.18 per Boe for the first nine months of 2013 compared to $17.17 per Boe for the same period in 2012. The decrease per Boe is largely due to a lower ratio of expense to production volumes on acquired properties.

Workover expenses increased $1.9 million for the nine months ended September 30, 2013 compared to the same period in 2012 primarily due to $2.8 million of expenses associated with acquired properties, including the increase in activity as we continue to develop these areas, partially offset by decreased workover expenses on our existing properties.

Taxes other than income increased $53.0 million for the nine months ended September 30, 2013 as compared to the same period in 2012 primarily due to $49.5 million of taxes associated with acquired properties and an increase in production within these areas as we continue to carry out our development plan. 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 $7.40 per Boe and $5.50 per Boe for the nine months ended September 30, 2013 and 2012, respectively.

Gathering and other expenses for the nine months ended September 30, 2013 and 2012 were $6.9 million and $0.3 million, respectively. In 2013, approximately $2.3 million of these expenses were attributable to midstream infrastructure that we developed in our Woodbine and Utica / Point Pleasant operating areas and approximately $4.6 million relates to gathering and other fees paid on our oil and natural gas production.

In March 2012, we announced our intention to close our Plano, Texas office and began the process of relocating key administrative functions to our corporate headquarters in Houston, Texas (the Restructuring). As part of the Restructuring, we offered certain severance and retention benefits to affected employees. We incurred $0.5 million and $1.7 million in costs associated with the Restructuring, which is now complete, for the nine months ended September 30, 2013 and 2012, respectively.

General and administrative expense for the nine months ended September 30, 2013 increased $26.6 million to $86.9 million as compared to the same period in 2012. The increase in general and administrative expenses is attributable to increases in payroll and related employee benefit costs of $20.6 million, office related expenses of $9.5 million and professional fees of $12.2 million, in support of our expanding business base and increased corporate activities subsequent to the Recapitalization. These increases were partially offset by a decrease in acquisition-related expenses, which were incurred in 2012 in conjunction with the Merger.

Share-based compensation expense for the nine months ended September 30, 2013 was $12.0 million, an increase of $6.0 million compared to the same period in 2012. In 2012, we incurred approximately $4.3 million for the accelerated vesting of restricted stock awards and stock appreciation rights resulting from the change in control that occurred due to the Recapitalization in February 2012. The year over year increase, excluding these change in control payments, approximates $1.7 million, which is a reflection of our investment in additional personnel since the prior year.

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 volume for the current period to total remaining reserve volume as of the beginning of the period for the evaluated properties. Depletion expense increased $280.5 million to $312.7 million for the nine months ended September 30, 2013 compared to the same period in 2012, primarily due to a higher depletion rate per Boe and increased production. On a per unit basis, depletion expense was $36.94 per Boe for the nine months ended September 30, 2013 compared to $18.32 per Boe for the nine months ended September 30, 2012. The increase in depletion expense and the depletion rate per Boe is primarily due to the increase in production volumes and reserves as a result of the Merger, the East Texas Acquisition and the Williston Basin Acquisitions during the third and fourth quarters of 2012. The aforementioned transfer of unevaluated property costs of $655.7 million to the full cost pool during the third quarter of 2013 also contributed to the increase in depletion expense on both an absolute dollar and per Boe basis as compared to the nine months ended September 30, 2012; however, the year-to-date per unit rate of $36.94 per Boe was lower than the third quarter 2013 rate due to per unit rates of $35.00 per Boe or lower in the first half of 2013.

Accretion expense is a function of changes in the discounted asset retirement obligation liability from period to period. We recorded accretion expense of $2.8 million for the nine months ended September 30, 2013, compared to $1.4 million for the same period in 2012.

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, 2013, we recorded a non-cash impairment charge of $67.3 million. The impairment relates to our gross investments of $68.3 million in gas gathering infrastructure that will not be economically recoverable due to our shift in exploration, drilling and developmental plans from the Woodbine area to El Halcón during the third quarter of 2013.

We enter into derivative commodity instruments to economically hedge our exposure to price fluctuations on our anticipated oil and natural gas production. We have also, in the past, entered into interest rate swaps to mitigate exposure to market rate fluctuations by converting variable interest rates to fixed interest rates. 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, 2013, we had an $8.9 million derivative asset, $3.2 million of which was classified as current, and we had a $31.5 million derivative liability, $30.4 million of which was classified as current. We recorded a net derivative loss of $38.8 million ($20.4 million net unrealized loss and $18.4 million net realized loss on settled contracts and premium costs) for the nine months ended September 30, 2013 compared to a net derivative loss of $0.8 million ($4.1 million net unrealized loss and $3.3 million net realized gain), in the same period in 2012.

Interest expense increased $2.0 million for the nine months ended September 30, 2013 from the same period in 2012. Capitalized interest for the nine months ended September 30, 2013 and 2012 was $159.6 million and $22.9 million, respectively. This increase in capitalized interest was driven by the increases in our unevaluated properties since September 30, 2012. Interest expense subject to capitalization increased to $186.0 million in the nine months ended September 30, 2013 from $45.0 million in the comparable prior year period. The increase in interest subject to capitalization is attributed to the issuance of our additional 2021 Notes and the 2022 Notes.

We recorded an income tax benefit of $333.9 million for the nine months ended September 30, 2013 due to our pre-tax loss of $1.1 billion compared to a tax provision of $1.2 million on a pre-tax loss of $44.7 million in the prior year. The effective tax rate for the nine months ending September 30, 2013 was 29.1% compared to 2.6% for the nine months ending September 30, 2012. The change in effective tax rate is primarily due to the pre-tax loss in the current year and the impact of federal income tax limitations on the deductibility of the goodwill impairment and interest expense on the 2017 Note issued as part of the Recapitalization in February 2012.

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

In the third quarter of 2013, we closed on the acquisition of certain oil and natural gas properties from an unaffiliated third party for approximately $2.1 million. In connection therewith, we paid a brokerage fee in the amount of $87,923 to Justin Elkouri, who located the selling party and assisted us in the acquisition. Justin Elkouri is not employed by us and provided services as an independent contractor in connection with the transaction. Justin Elkouri is the adult son of David S. Elkouri, our Executive Vice President and General Counsel. Mr. Elkouri has no financial interest in the transaction or in any fee paid to his son. The brokerage fee paid to Justin Elkouri is commensurate with brokerage fees we pay to unrelated third parties under similar circumstances, and the fee was reviewed and approved by our Audit Committee in accordance with our policies and procedures relating to transactions involving executives and members of their family.

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. We expect energy prices to remain volatile and unpredictable, therefore we

have designed a risk management policy which provides for the use of derivative instruments to provide partial protection against declines in oil 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 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 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, including interest rate swaps, only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. Each of the counterparties to our derivative contracts is a lender or an affiliate of a lender in our Senior Credit Agreement. We did not post collateral under any of these contracts as they are secured under the Senior Credit Agreement. Please refer to Item 1. Condensed Consolidated Financial Statements (Unaudited)—Note 8, "Derivative and Hedging Activities" for additional information.

We have also been exposed to interest rate risk on our variable interest rate debt. If interest rates increase, our interest expense would increase and our available cash flow would decrease. Historically, we entered into interest rate swaps to reduce the exposure to market rate fluctuations by converting variable interest rates to fixed interest rates. At September 30, 2013, we did not have any open positions that converted our variable interest rate debt to fixed interest rates. We continue to monitor our risk exposure as we incur future indebtedness at variable interest rates and will look to continue our risk management policy as situations present themselves.

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 8, "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 7, "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, 2013, total long-term debt was approximately $3.0 billion of which approximately 92% bears interest at a weighted average fixed interest rate of 9.1% per year. The remaining 8% of our total debt balance at September 30, 2013 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, 2013, the weighted average interest rate on our variable rate debt was 2.3% per year. If the balance of our variable rate debt at September 30, 2013 were to

remain constant, a 10% change in market interest rates would impact our cash flow by approximately $0.1 million per quarter.

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, 2013. 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, 2013 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 year ended December 31, 2012, except as described below.

We may have difficulty financing our planned capital expenditures which could adversely affect our growth.

We have experienced, and expect to continue to experience, substantial capital expenditure and working capital needs, primarily as a result of our drilling program. We intend to continue to selectively increase our acreage position, which would require capital in addition to the capital necessary to drill on our existing acreage. In addition, it is likely that we will acquire acreage in other areas that we believe are prospective for oil and natural gas production and expend capital to develop such acreage. We expect to use borrowings under our Senior Credit Agreement, proceeds from potential asset dispositions and proceeds from potential future capital markets transactions, if necessary, to fund capital expenditures that are in excess of our cash flow and cash on hand.

Our Senior Credit Agreement limits our borrowings to the lesser of the borrowing base and the total commitments. Our borrowing base is currently $850.0 million, which was affirmed in the redetermination which occurred on October 31, 2013. Should all three of our non-core divestitures successfully close, the borrowing base will be reduced to $800.0 million. Our borrowing base is determined semi-annually, and may also be redetermined periodically at the discretion of the banks. Lower oil and natural gas prices may result in a reduction in our borrowing base at the next redetermination. A reduction in our borrowing base could require us to repay any indebtedness in excess of the borrowing base. Additionally, the indentures governing our senior unsecured 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 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 under the most restrictive indenture. The second test applies only to borrowings under credit agreements, including indentures and our Senior Credit Agreement, that do not meet the first test and it limits these borrowings to the greater of a fixed sum of $750 million and 30% of our adjusted consolidated net tangible assets (as defined in all of our indentures), which is determined using discounted future net revenues from proved oil and natural gas reserves as of the end of each year. Currently, we are permitted to incur additional indebtedness under our indentures, but may be limited in the future. Lower oil and natural gas prices in the future could reduce our adjusted consolidated EBITDA, as well as our adjusted consolidated net tangible assets, and thus could reduce our ability to incur additional indebtedness.

Additionally, our ability to complete future equity offerings is limited by general market conditions. If we are not able to borrow sufficient amounts under our Senior Credit Agreement and/or are unable to raise sufficient capital to fund our 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, forfeiture of leasehold interests if we are unable or unwilling to renew them, and

could force us to sell some of our assets on an untimely or unfavorable basis, each of which could have a material adverse effect on our results and future operations.

We are subject to various contractual limitations that affect the discretion of our management in operating our business.

The indentures governing our senior unsecured debt and our Senior Credit Agreement and the certificate of designations governing our outstanding preferred stock contain various provisions that may limit our management's discretion in certain respects. In particular, these agreements limit our and our subsidiaries' ability to, among other things:

Additionally, if dividends on our outstanding preferred stock are in arrears and unpaid for six or more quarterly periods, the holders (voting as a single class) of our outstanding preferred stock will be entitled to elect two additional directors to our Board of Directors until paid in full.

Compliance with these and other limitations may limit our ability to operate and finance our business and engage in certain transactions in the manner we might otherwise. In addition, if we fail to comply with the limitations under our indentures or Senior Credit Agreement, our creditors, if the agreements so provide, may accelerate the related indebtedness as well as any other indebtedness to which a cross-acceleration or cross-default provision applies. In addition, lenders may be able to terminate any commitments they had made to make further funds available to us.

Offers or sales of a substantial number of shares of our common stock by our shareholders may cause the market price of our common stock to decline.

In satisfaction of pre-existing contractual obligations, we recently filed with the SEC a shelf registration statement on Form S-3 covering the potential resale by certain selling stockholders of approximately 158.0 million shares of our common stock, and have previously filed similar resale registration statements in lesser amounts for other shareholders. The ability of our shareholders to sell significant numbers of shares of our common stock in the public market pursuant to such registration

statements or upon the expiration of lock up agreements or statutory holding periods under Rule 144 of the Securities Act of 1933, as amended, together with any actual sales of our common stock they may chose to make, could cause the market price of our common stock to fall and could make it more difficult for us to raise additional financing through future sales of equity or equity-related securities at a time and price that we deem reasonable or appropriate.

If we were to experience an ownership change, we could be limited in our ability to use net operating losses arising prior to the ownership change to offset future taxable income.

If we were to experience an "ownership change," as determined under section 382 of the Internal Revenue Code, our ability to offset taxable income arising after the ownership change with net operating losses (NOLs) arising prior to the ownership change would be limited, possibly substantially. An ownership change would establish an annual limitation on the amount of our pre-change NOLs we could utilize to offset our taxable income in any future taxable year to an amount generally equal to the value of our stock immediately prior to the ownership change multiplied by the long-term tax-exempt rate.

We depend on computer and telecommunications systems and failures in our systems or cyber security attacks could significantly disrupt our business operations.

We have entered into agreements with third parties for hardware, software, telecommunications and other information technology services in connection with our business. In addition, we have developed proprietary software systems, management techniques and other information technologies incorporating software licensed from third parties. It is possible we could incur interruptions from cyber security attacks, computer viruses or malware. We believe that we have positive relations with our related vendors and maintain adequate anti-virus and malware software and controls; however, any interruptions to our arrangements with third parties to our computing and communications infrastructure or our information systems could significantly disrupt our business operations.

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 RAM Energy Resources, Inc. dated February 8, 2012 (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed February 9, 2012).

3.2		Certificate of Amendment of the Amended and Restated Certificate of Incorporation of Halcón Resources Corporation, effective as of February 10, 2012 (Incorporated by reference to Exhibit 3.2 of our Current Report on Form 8-K filed February 9, 2012).

3.3		Certificate of Designation, Preferences, Rights and Limitations of 8% Automatically Convertible Preferred Stock of Halcón Resources Corporation dated March 2, 2012 (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed March 5, 2012).

3.4		Certificate of Elimination of 8% Automatically Convertible Preferred Stock dated November 30, 2012 (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed December 4, 2012).

3.5		Certificate of Designation, Preferences, Rights and Limitations of 8% Automatically Convertible Preferred Stock of Halcón Resources Corporation dated December 5, 2012 (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed December 11, 2012).

3.6		Certificate of Amendment of the Amended and Restated Certificate of Incorporation of Halcón Resources Corporation dated January 17, 2013 (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed January 23, 2013).

3.7		Fourth Amended and Restated Bylaws of Halcón Resources Corporation (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed November 6, 2012).

3.8		Certificate of Amendment of the Amended and Restated Certificate of Incorporation of Halcón Resources Corporation, effective as of May 23, 2013 (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed May 29, 2013).

3.9		Certificate of Designations, Preferences, Rights and Limitations of 5.75% Series A Convertible Perpetual Preferred Stock of Halcón Resources Corporation (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed June 18, 2013).

3.10		Certificate of Elimination of 8% Automatically Convertible Preferred Stock of Halcón Resources Corporation (Incorporated by reference to Exhibit 3.2 of our Current Report on Form 8-K filed June 18, 2013).

4.1		Convertible Promissory Note dated February 8, 2012, between Halcón Resources Corporation and HALRES LLC (formerly Halcón Resources LLC) (Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed February 9, 2012).


4.2		Warrant Certificate dated February 8, 2012, between Halcón Resources Corporation and HALRES LLC (formerly Halcón Resources LLC) (Incorporated by reference to Exhibit 4.2 of our Current Report on Form 8-K filed February 9, 2012).

4.3		Registration Rights Agreement dated February 8, 2012, between Halcón Resources Corporation and HALRES LLC (formerly Halcón Resources LLC) (Incorporated by reference to Exhibit 4.3 of our Current Report on Form 8-K filed February 9, 2012).

4.4		Indenture dated as of July 16, 2012, among Halcón Resources Corporation, the subsidiary guarantors named therein and U.S. Bank National Association, as Trustee, relating to Halcón Resources Corporation's 9.75% Senior Notes due 2020 (Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed July 17, 2012).

4.5		Registration Rights Agreement dated July 16, 2012, among Halcón Resources Corporation, the subsidiary guarantors named therein, and the initial purchaser named therein (Incorporated by reference to Exhibit 4.2 of our Current Report on Form 8-K filed July 17, 2012).

4.6		First Supplemental Indenture dated as of August 1, 2012, by and among Halcón Resources Corporation, the parties named therein as subsidiary guarantors, and U.S. Bank National Association, as Trustee, relating to the 9.75% senior notes due 2020 (Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed August 2, 2012).

4.7		Second Supplemental Indenture dated as of August 1, 2012, by and among Halcón Resources Corporation, the parties named therein as subsidiary guarantors, and U.S. Bank National Association, as Trustee, relating to the 9.75% senior notes due 2020 (Incorporated by reference to Exhibit 4.2 of our Current Report on Form 8-K filed August 2, 2012).

4.8		Registration Rights Agreement dated as of August 1, 2012, among CH4 Energy II, LLC, PetroMax Leon, LLC and Petro Texas LLC and Halcón Resources Corporation (subsequently joined by U.S. King King LLC) (Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed August 7, 2012).

4.9		Registration Rights Agreement dated March 5, 2012, between Halcón Resources Corporation and Barclays Capital, Inc. as lead placement agent for the benefit of the initial holders named therein (Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed March 5, 2012).

4.10		Registration Rights Agreement dated as of November 6, 2012, among Halcón Resources Corporation, the subsidiary guarantors named therein, and the initial purchaser named therein (Incorporated by reference to Exhibit 4.2 of our Current Report on Form 8-K filed November 7, 2012).

4.11		Indenture dated as of November 6, 2012, among Halcón Resources Corporation, the subsidiary guarantors named therein and U.S. Bank National Association, as Trustee, relating to Halcón Resources Corporation's 8.875% Senior Notes due 2021 (Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed November 7, 2012).

4.12		First Supplemental Indenture dated December 6, 2012, among Halcón Williston I, LLC and Halcón Williston II, LLC, the existing guarantors, Halcón Resources Corporation, the parties named therein as subsidiary guarantors and U.S. Bank National Association, as trustee, relating to the 8.875% senior notes due 2021 (Incorporated by reference to Exhibit 4.3 of our Current Report on Form 8-K filed December 11, 2012).


4.13		Third Supplemental Indenture dated December 6, 2012, among Halcón Resources Corporation and U.S. Bank National Association, as Trustee, relating to the 9.75% senior notes due 2020 (Incorporated by reference to Exhibit 4.4 of our Current Report on Form 8-K filed December 11, 2012).

4.14		Registration Rights Agreement dated December 6, 2012, between Halcón Resources Corporation and Petro-Hunt Holdings LLC and Pillar Holdings LLC (Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed December 11, 2012).

4.15		First Amendment to Registration Rights Agreement dated December 6, 2012, between Halcón Resources Corporation and HALRES LLC (formerly Halcón Resources LLC) (Incorporated by reference to Exhibit 4.2 of our Current Report on Form 8-K filed December 11, 2012).

4.16		Registration Rights Agreement, dated as of January 14, 2013, between Halcón Resources Corporation and Wells Fargo Securities, LLC, on behalf of the initial purchasers named therein (Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed January 15, 2013).

4.17		Waiver, dated July 3, 2013, relating to Registration Rights Agreement dated December 6, 2012 by and among Halcón Resources Corporation and Petro-Hunt Holdings, LLC and Pillar Holdings, LLC (Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed July 10, 2013).

4.18		Indenture dated as of August 13, 2013, among Halcón Resources Corporation, the subsidiary guarantors named therein and U.S. Bank National Association, as Trustee, relating to Halcón Resources Corporation's 9.25% Senior Notes due 2022 (Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed August 13, 2013).

4.19		Registration Rights Agreement dated as of August 13, 2013, among Halcón Resources Corporation and BMO Capital Markets Corp., on behalf of the initial purchaser named therein (Incorporated by reference to Exhibit 4.2 of our Current Report on Form 8-K filed August 13, 2013).

10.1		Second Amendment to Senior Revolving Credit Agreement, dated as of January 25, 2013, among Halcón Resources Corporation, as borrower, each of the lenders from time to time party thereto, and JPMorgan Chase Bank, N.A., as administrative agent for the lenders (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed January 30, 2013).

10.2		Third Amendment to Senior Revolving Credit Agreement, dated as of April 26, 2013, among Halcón Resources Corporation, as borrower, each of the lenders from time to time party thereto, and JPMorgan Chase Bank, N.A., as administrative agent for the lenders (Incorporated by reference to Exhibit 10.2 of our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2013).

10.3		Purchase Agreement, dated January 9, 2013, among Halcón Resources Corporation, the subsidiary guarantors named therein and Wells Fargo Securities, LLC, as representative of the initial purchasers named therein (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed January 15, 2013).

10.4		Fourth Amendment to Senior Revolving Credit Agreement, dated as of May 8, 2013, among Halcón Resources Corporation, as borrower, each of the lenders from time to time party thereto, and JPMorgan Chase Bank, N.A., as administrative agent for the lenders (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed May 14, 2013).



10.5		Fifth Amendment to Senior Revolving Credit Agreement, dated as of June 11, 2013, among Halcón Resources Corporation, as borrower, each of the lenders party thereto, and JPMorgan Chase Bank, N.A., as administrative agent for the lenders (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed June 17, 2013).

10.6		Underwriting Agreement, dated June 13, 2013, among Halcón Resources Corporation, J.P. Morgan Securities LLC and Barclays Capital Inc., as representatives of the underwriters named therein (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed June 18, 2013).

10.7		Underwriting Agreement, dated August 8, 2013, among Halcón Resources Corporation and Barclays Capital Inc., as representatives of the underwriters named therein (Incorporated by reference to Exhibit 1.1 of our Current Report on Form 8-K filed August 13, 2013).

10.8		Purchase Agreement, dated August 8, 2013, among Halcón Resources Corporation and BMO Capital Markets Corp., as representatives of the initial purchasers named therein (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed August 13, 2013).

10.9	†	Halcón Resources Corporation First Amended and Restated 2012 Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.01 of our Current Report on Form 8-K filed March 4, 2013).

10.10	†	Amendment No. 1 to Halcón Resources Corporation First Amended and Restated 2012 Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed May 29, 2013).

10.11	*	Sixth Amendment to Senior Revolving Credit Agreement, dated as of October 31, 2013, among Halcón Resources Corporation, as borrower, each of the lenders party thereto, and JPMorgan Chase Bank, N.A., as administrative agent for the lenders.

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

31.1	*	Sarbanes-Oxley Section 302 certification of our Principal Executive Officer

31.2	*	Sarbanes-Oxley Section 302 certification of our 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, 2013
OR
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to


Large Accelerated Filer o		Accelerated Filer ý		Non-Accelerated Filer o (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, 2013 and 2012	5
	Condensed Consolidated Balance Sheets (Unaudited) as of September 30, 2013 and December 31, 2012	6
	Condensed Consolidated Statements of Stockholders' Equity (Unaudited) for the Nine Months Ended September 30, 2013 and Year Ended December 31, 2012	7
	Condensed Consolidated Statements of Cash Flows (Unaudited) for the Nine Months Ended September 30, 2013 and 2012	8
	Notes to Unaudited Condensed Consolidated Financial Statements	9
ITEM 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	41
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	55
ITEM 4.	Controls and Procedures	57
PART II—OTHER INFORMATION
ITEM 1.	Legal Proceedings	58
ITEM 1A.	Risk Factors	58
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	60
ITEM 3.	Defaults Upon Senior Securities	60
ITEM 4.	Mine Safety Disclosures	60
ITEM 5.	Other Information	61
ITEM 6.	Exhibits	61
Signatures		65

	Severance Program

	(In thousands)
Ending balance, December 31, 2012	$	2,131
Severance and retention payments		(2,627	)
Net increase in accrual		496

Ending balance, September 30, 2013	$	—

(In thousands, except per share amounts)	Three Months Ended September 30, 2012 (Unaudited)		Nine Months Ended September 30, 2012 (Unaudited)

Revenue	$	152,723	$	431,038
Net income (loss)		6,850		37,344
Net income (loss) available to Halcón common stockholders		6,850		(51,101	)
Pro forma net income (loss) per common share:
Basic	$	0.02	$	(0.17	)
Diluted	$	0.02	$	(0.17	)


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, 2013⁽¹⁾		December 31, 2012⁽¹⁾

	(In thousands)
Senior revolving credit facility	$	232,000	$	298,000
9.25% $400 million senior notes⁽²⁾		400,000		—
8.875% $1.35 billion senior notes⁽³⁾		1,372,877		744,421
9.75% $750 million senior notes⁽⁴⁾		740,899		740,232
8.0% $275 million convertible note⁽⁵⁾		257,385		251,845
Deferred premiums on derivative contracts		694		—

	$	3,003,855	$	2,034,498

	September 30, 2013

	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets
Receivables from derivative contracts	$	—	$	8,875	$	—	$	8,875

Liabilities
Liabilities from derivative contracts	$	—	$	31,533	$	—	$	31,533

	September 30, 2013				December 31, 2012

Debt	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
	(In thousands)
9.25% $400 million senior notes	$	400,000	$	420,216	$	—	$	—
8.875% $1.35 billion senior notes		1,350,000		1,387,125		750,000		798,750
9.75% $750 million senior notes		750,000		798,750		750,000		815,160
8.0% $275 million convertible note		289,669		408,527		289,669		625,425

	$	2,789,669	$	3,014,618	$	1,789,669	$	2,239,335

		Asset derivative contracts					Liability derivative contracts

Derivatives not designated as hedging contracts under ASC 815	Balance sheet location	September 30, 2013		December 31, 2012		Balance sheet location	September 30, 2013			December 31, 2012
		(In thousands)					(In thousands)
Commodity contracts	Current assets—receivables from derivative contracts	$	3,246	$	7,428	Current liabilities—liabilities from derivative contracts	$	(30,387	)	$	(10,429	)
Commodity contracts	Other noncurrent assets—receivables from derivative contracts		5,629		371	Other noncurrent liabilities—liabilities from derivative contracts		(1,146	)		(2,461	)

Total derivatives not designated as hedging contracts under ASC 815		$	8,875	$	7,799		$	(31,533	)	$	(12,890	)

	Derivative Assets						Derivative Liabilities

Offsetting of Derivative Assets and Liabilities	September 30, 2013			December 31, 2012			September 30, 2013			December 31, 2012
	(In thousands)						(In thousands)
Gross Amounts Presented in the Consolidated Balance Sheet	$	8,875		$	7,799		$	(31,533	)	$	(12,890	)
Amounts Not Offset in the Consolidated Balance Sheet		(3,790	)		(4,118	)		3,696			3,899

Net Amount	$	5,085		$	3,681		$	(27,837	)	$	(8,991	)


Liability for asset retirement obligations as of December 31, 2012	$	75,132
Liabilities settled and divested		(2,717	)
Additions		9,395
Acquisitions		3,832
Accretion expense		2,828
Revisions in estimated cash flows		(433	)

Liability for asset retirement obligations as of September 30, 2013	$	88,037

		Average Price Paid Per Share

July 2013	—	$	—	—	—
August 2013	911		6.01	—	—
September 2013	—		—	—	—


	HALCÓN RESOURCES CORPORATION
November 4, 2013	By:	/s/ FLOYD C. WILSON
		Name:	Floyd C. Wilson
		Title:	Chairman of the Board and Chief Executive Officer
November 4, 2013	By:	/s/ MARK J. MIZE
		Name:	Mark J. Mize
		Title:	Executive Vice President, Chief Financial Officer and Treasurer
November 4, 2013	By:	/s/ JOSEPH S. RINANDO, III
		Name:	Joseph S. Rinando, III
		Title:	Vice President and Chief Accounting Officer