10-Q

10-Q/A 1 kwk10-qa20150930.htm 10-Q/A 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q/A

Amendment No. 1



(Mark One)
þ	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2015
or

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

For the transition period from to

Commission file number: 001-14837

Quicksilver Resources Inc.

(Exact name of registrant as specified in its charter)



Delaware		75-2756163
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

801 Cherry Street, Suite 3700, Unit 19, Fort Worth, Texas		76102
(Address of principal executive offices)		(Zip Code)

(817) 665-5000

(Registrant’s telephone number, including area code)

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 12 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 þ No ¨

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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No ¨

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. (Check one):



Large accelerated filer	¨		Accelerated filer	þ
Non-accelerated filer	¨	(Do not check if a smaller reporting company)	Smaller reporting company	¨

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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:



Title of Class		Outstanding as of October 16, 2015
Common Stock, $0.01 par value		183,084,886 shares

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Explanatory Note

We are amending and restating in their entirety the following items of our Quarterly Report on Form 10-Q for the period ended September 30, 2015 as originally filed with the Securities and Exchange Commission on October 30, 2015 (our “Original Report”): (i) Item 1 of Part I “Financial Statements,” (ii) Item 2 of Part I, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” (iii) Item 4 of Part I, “Controls and Procedures,” and (iv) Item 6 of Part II, “Exhibits,” after identifying certain non-cash errors in such financial statements caused by the fact that the estimate of our proved oil and natural gas reserves as of September 30, 2015 overstated the net proved reserves, with the error in such report occurring as the result of all applicable costs not being considered when preparing the operating cost estimate for the reserve report. The adjustments are more fully described in Note 1 to the restated condensed consolidated financial statements presented in this Form 10-Q/A. We have also updated the signature page and the certifications of our Chief Executive Officer and Chief Financial Officer in Exhibits 31.1, 31.2 and 32.1. No other sections of our Original Report are affected by this amendment. For the convenience of the reader, we are re-filing the Original Report in its entirety in this Form 10-Q/A. This Form 10-Q/A continues to speak as of the date of the Original Report and other than with respect to the restatement of the Company’s financial statements and other financial information as described above does not reflect events occurring after the filing of the Original Report. The financial and other information contained in the Original Report should no longer be relied upon.

DEFINITIONS

As used in this Quarterly Report unless the context otherwise requires:

“ABR” means alternate base rate

“AOCI” means accumulated other comprehensive income

“ASC” means FASB Accounting Standards Codification

“Bbl” or “Bbls” means barrel or barrels

“Bbld” means barrel or barrels per day

“BTU” means British Thermal Units, a measure of heating value, and is approximately equal to one Mcf of natural gas

“Canada” means our oil and natural gas operations located principally in British Columbia and Alberta, Canada

“C$” means Canadian dollars

“DD&A” means depletion, depreciation and accretion

“GPT” means gathering, processing and transportation expense

“LIBOR” means London Interbank Offered Rate

“MBbl” or “MBbls” means thousand barrels

“MMBtu” means million BTUs

“Mcf” means thousand cubic feet

“Mcfe” means Mcf natural gas equivalent, calculated as one Bbl of oil or NGLs equaling six Mcf of gas

“MMcf” means million cubic feet

“MMcfd” means million cubic feet per day

“MMcfe” means MMcf of natural gas equivalent

“MMcfed” means MMcfe per day

“NGL” or “NGLs” means natural gas liquids

“OCI” means other comprehensive income

“Oil” includes crude oil and condensate

“QRCI” means Quicksilver Resources Canada Inc., our wholly owned subsidiary

“RSU” means restricted stock unit

COMMONLY USED TERMS

Other commonly used terms and abbreviations include:

“Amended and Restated Canadian Credit Facility” means our Canadian senior secured revolving credit facility which was amended and restated, effective December 22, 2011, and as further amended, restated, supplemented or otherwise modified

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“Amended and Restated U.S. Credit Facility” means our U.S. senior secured revolving credit facility which was amended and restated, effective December 22, 2011, and as further amended, restated, supplemented or otherwise modified

“Bankruptcy Code” means title 11 of the United States Code

“Bankruptcy Court” means the United States Bankruptcy Court for the District of Delaware

“Bar Date” means July 31, 2015 for general claims and September 14, 2015 for government claims and is the general deadline set by the Bankruptcy Court for the filing of proofs of claim by certain pre-petition creditors to formally assert claims against the U.S. Debtors

“Barnett Shale Asset” means our operations and our assets in the Barnett Shale located in the Fort Worth basin of North Texas

“CCAA” means the Companies’ Creditors Arrangement Act (Canada)

“Chapter 11” means chapter 11 of the Bankruptcy Code

“CMLP” means Crestwood Midstream Partners LP

“Combined Credit Agreements” means collectively our Amended and Restated U.S. Credit Facility and our Amended and Restated Canadian Credit Facility

“Creditors Committee” means the official committee of unsecured creditors appointed by the United States Trustee for Delaware under the Bankruptcy Code

“Eni” means either or both Eni Petroleum US LLC and Eni US Operating Co. Inc., which are subsidiaries of Eni SpA

“Exclusive Filing Period” means the exclusive period to file a chapter 11 plan

“Exclusive Periods” means the Exclusive Filing Period and the Exclusive Solicitation Period

“Exclusive Solicitation Period” means the exclusive period to solicit acceptance of a chapter 11 plan

“FASB” means the Financial Accounting Standards Board, which promulgates accounting standards in the U.S.

“Forbearance Agreement” means the Waiver and Forbearance Agreement entered into by us and QRCI on March 16, 2015 with the administrative agents and certain of the lenders under the Combined Credit Agreements

“Forbearance Agreements” means the Forbearance Agreement, Second Forbearance Agreement and Third Forbearance Agreement

“Fortune Creek” means Fortune Creek Gathering and Processing Partnership, a midstream partnership formed with KKR and dedicated to the construction and operation of natural gas midstream services within the Horn River basin of northeast British Columbia

“GAAP” means accounting principles generally accepted in the U.S.

“Horn River Asset” means our operations and our assets in the Horn River basin of northeast British Columbia

“Horseshoe Canyon Asset” means our operations and our assets in Horseshoe Canyon, the coalbed methane fields of southern and central Alberta

“Houlihan Lokey” means Houlihan Lokey Capital, Inc.

“KKR” means Kohlberg Kravis Roberts & Co. L.P., with whom we formed Fortune Creek

“Mercury” means Mercury Exploration Company, which is owned by members of the Darden family

“Niobrara Asset” means our operations and our assets in the Niobrara formation in northwest Colorado, which we were jointly developing with SWEPI LP and which were sold in the Southwestern Transaction

“OTC Pink” means OTC Pink, a centralized electronic quotation service for over-the-counter securities, operated by OTC Markets Group Inc.

“Petition Date” means March 17, 2015

“Schedules and Statements” means the schedules of assets and liabilities and statements of financial affairs that were filed on June 9, 2015 by the U.S. Debtors with the Bankruptcy Court, together with any amendments, supplements and modifications

“SEC” means the U.S. Securities and Exchange Commission

“Second Forbearance Agreement” means the Second Waiver and Forbearance Agreement entered into by QRCI on June 15, 2015 with the administrative agents and certain of the lenders under the Combined Credit Agreements

“Second Lien Notes” means our senior secured second lien notes issued June 21, 2013

“Second Lien Term Loan” means our senior secured second lien term loan facility, effective June 21, 2013

“Southwestern” means Southwestern Energy Company

“Southwestern Transaction” means the sale of our Niobrara Asset to Southwestern

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“Substantial Equityholder” means all persons or entities who at March 19, 2015 or in the future beneficially own at least 4.75% of our outstanding equity securities

“Third Forbearance Agreement” means the Third Forbearance Agreement entered into by QRCI on September 15, 2015 with the administrative agents and certain of the lenders under the Combined Credit Agreements

“U.S. Debtors” means us and our subsidiaries Barnett Shale Operating LLC, Cowtown Drilling, Inc., Cowtown Gas Processing L.P., Cowtown Pipeline Funding, Inc., Cowtown Pipeline L.P., Cowtown Pipeline Management, Inc., Makarios Resources International Holdings LLC, Makarios Resources International Inc., QPP Holdings LLC, QPP Parent LLC, Quicksilver Production Partners GP LLC, Quicksilver Production Partners LP, and Silver Stream Pipeline Company LLC that filed Chapter 11 petitions

“VIE” means variable interest entity

“West Texas Asset” means our operations and our assets in the Delaware basin in West Texas which we believe is prospective for the Bone Springs and Wolfcamp formations, principally concentrated in Pecos County, Texas and to a lesser extent Crockett and Upton Counties, Texas

INDEX TO QUARTERLY REPORT ON FORM 10-Q/A

For the Quarter Ended September 30, 2015



PART I. FINANCIAL INFORMATION	8

Item 1. Condensed Consolidated Interim Financial Statements (Unaudited)	8

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	39

Item 3. Quantitative and Qualitative Disclosures About Market Risk	67

Item 4. Controls and Procedures	68

PART II. OTHER INFORMATION	69

Item 1. Legal Proceedings	69

Item 1A. Risk Factors	69

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	69

Item 3. Defaults Upon Senior Securities	69

Item 4. Mine Safety Disclosures	69

Item 5. Other Information	69

Item 6. Exhibits	70

Signature	71

Except as otherwise specified and unless the context otherwise requires, references to the “Company,” “Quicksilver,” “we,” “us,” and “our” refer to Quicksilver Resources Inc. and its subsidiaries.

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Forward-Looking Information

Certain statements contained in this Quarterly Report and other materials we file with the SEC, or in other written or oral statements made or to be made by us, other than statements of historical fact, are “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995. Forward-looking statements give our current expectations or forecasts of future events. Words such as “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “contemplate,” “estimate,” “anticipate,” “believe,” “project,” “target,” “budget,” “potential,” or “continue,” and similar expressions are used to identify forward-looking statements. Forward-looking statements can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed. Actual results may vary materially. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:


•	risks and uncertainties associated with the Chapter 11 process, including our inability to develop, confirm and consummate a plan under Chapter 11 or an alternative restructuring transaction, including a sale of all or substantially all of our assets, which may be necessary to continue as a going concern;


•	inability to maintain relationships with suppliers, customers, employees and other third parties as a result of our Chapter 11 filing;


•	a filing by QRCI for creditor protection under the CCAA;


•	failure to satisfy our short- or long-term liquidity needs, including our inability to generate sufficient cash flow from operations or to obtain adequate financing to fund our capital expenditures, meet working capital needs and make adequate protection payments, and our ability to continue as a going concern;


•	domestic and foreign supply and demand for natural gas, NGL and oil and related fluctuations in natural gas, NGL and oil prices;


•	failure or delays in achieving expected production from exploration and development projects;


•	our ability to achieve anticipated cost savings and other spending reductions and operational efficiencies;


•	our ability to secure alternative gathering and processing in our Horn River Basin Asset;


•	uncertainties inherent in estimates of natural gas, NGL and oil reserves and predicting natural gas, NGL and oil production and reservoir performance;


•	our inability to manage our exposure to fluctuations in commodity prices;


•	fluctuations in the value of certain of our assets and liabilities;


•	competitive conditions in our industry;


•	actions taken or non-performance by third parties, including suppliers, contractors, operators, processors, transporters, customers and counterparties;


•	the volatility and decline in our stock price, and the inability of our common stock to remain quoted on the OTC Pink;


•	delays in obtaining oilfield equipment and increases in drilling and completion and other service costs;


•	delays in construction of transportation pipelines and gathering, processing and treating facilities;


•	operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond our control;


•	the effects of existing and future laws and governmental regulations, including environmental and climate change requirements;


•	failure or delay in completing strategic transactions;


•	failure to make the necessary expenditures under or related to our contractual commitments, including our spending requirement pursuant to Fortune Creek;


•	inability to meet our minimum volume delivery requirements in our gathering, processing and transportation agreements or otherwise satisfy minimum volume deficiency payment obligations;


•	the effects of existing or future litigation;


•	changes in general economic conditions; and


•	additional factors described elsewhere in this Quarterly Report.

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This list of factors is not exhaustive, and new factors may emerge or changes to these factors may occur that would impact our business. Additional information regarding these and other factors may be contained in our filings with the SEC, especially on Forms 10-K, 10-Q and 8-K, including any amendments thereto. All such risk factors are difficult to predict, and are subject to material uncertainties that may affect actual results and may be beyond our control. The forward-looking statements included in this Quarterly Report are made only as of the date of this Quarterly Report, and we undertake no obligation to update any of these forward-looking statements to reflect subsequent events or circumstances except to the extent required by applicable law.

All forward-looking statements are expressly qualified in their entirety by the foregoing cautionary statements.

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PART I FINANCIAL INFORMATION


ITEM 1.	Condensed Consolidated Interim Financial Statements (Unaudited)

QUICKSILVER RESOURCES INC. (DEBTOR IN POSSESSION)

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)

In thousands, except for per share data – Unaudited



	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2015			2014			2015			2014
	(Restated)						(Restated)
Revenue
Production	$	49,437		$	102,615		$	161,875		$	332,187
Sales of purchased natural gas	8,342			16,660			29,921			53,401
Net derivative gains (losses)	261			43,310			27,863			(15,080		)
Other	947			913			7,460			2,808
Total revenue	58,987			163,498			227,119			373,316
Operating expense
Lease operating	12,506			17,176			39,763			54,622
Gathering, processing and transportation	17,799			34,807			65,270			102,511
Production and ad valorem taxes	773			4,067			8,046			12,557
Costs of purchased natural gas	8,319			16,599			29,863			53,305
Depletion, depreciation and accretion	11,650			13,969			39,793			42,584
Impairment	164,518			135			241,929			135
General and administrative	10,221			11,310			39,312			38,115
Other operating	248			651			937			2,221
Total expense	226,034			98,714			464,913			306,050
Operating income (loss)	(167,047		)	64,784			(237,794		)	67,266
Other expense - net	(659		)	(2,465		)	(26,106		)	(3,824		)
Fortune Creek accretion	(3,279		)	(3,602		)	(9,877		)	(11,605		)
Interest expense (contractual interest expense equals $39,413 and $118,286 for the three and nine months ended September 30, 2015, respectively)	(3,192		)	(39,899		)	(43,537		)	(121,927		)
Reorganization items, net	(7,883		)	—			(148,568		)	—
Income (loss) before income taxes	(182,060		)	18,818			(465,882		)	(70,090		)
Income tax benefit (expense)	(2,152		)	4,939			(5,836		)	(1,081		)
Net income (loss)	$	(184,212	)	$	23,757		$	(471,718	)	$	(71,171	)
Reclassification adjustments related to settlements of derivative contracts into production revenue- net of income tax	(5,757		)	(7,968		)	(17,553		)	(20,939		)
Foreign currency translation adjustment	98			(6,921		)	(5,996		)	(6,162		)
Other comprehensive loss	(5,659		)	(14,889		)	(23,549		)	(27,101		)
Comprehensive income (loss)	$	(189,871	)	$	8,868		$	(495,267	)	$	(98,272	)
Earnings (loss) per common share - basic	$	(1.05	)	$	0.13		$	(2.68	)	$	(0.41	)
Earnings (loss) per common share - diluted	$	(1.05	)	$	0.13		$	(2.68	)	$	(0.41	)

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

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QUICKSILVER RESOURCES INC. (DEBTOR IN POSSESSION)

CONDENSED CONSOLIDATED BALANCE SHEETS

In thousands, except for share data – Unaudited



	September 30, 2015			December 31, 2014
ASSETS	(Restated)
Current assets
Cash and cash equivalents	$	175,673		$	223,529
Accounts receivable - net of allowance for doubtful accounts	27,537			65,158
Derivative assets at fair value	—			120,176
Other current assets	17,794			14,414
Total current assets	221,004			423,277
Property, plant and equipment - net
Oil and natural gas properties, full cost method (including unevaluated costs of $21,377 and $18,803, respectively)	341,488			614,668
Other property and equipment	99,332			114,112
Property, plant and equipment - net	440,820			728,780
Derivative assets at fair value	—			29,391
Other assets	6,640			32,854
	$	668,464		$	1,214,302
LIABILITIES AND EQUITY
Current liabilities
Current portion of long-term debt	$	156,985		$	2,037,305
Accounts payable	19,528			22,586
Accrued liabilities	38,004			81,146
Total current liabilities	214,517			2,141,037
Partnership liability	87,935			91,956
Asset retirement obligations	99,791			104,049
Other liabilities	10,195			15,131
Liabilities subject to compromise	1,884,128			—
Commitments and contingencies (Note 7)
Stockholders' equity
Preferred stock, par value $0.01, 10,000,000 shares authorized, none outstanding	—			—
Common stock, $0.01 par value, 400,000,000 shares authorized, and 191,487,376 and 187,802,994 shares issued, respectively	1,915			1,878
Additional paid in capital	786,783			781,669
Treasury stock of 8,378,865 and 7,444,372 shares, respectively	(53,925		)	(53,810		)
Accumulated other comprehensive income	48,304			71,853
Retained deficit	(2,411,179		)	(1,939,461		)
Total stockholders' equity	(1,628,102		)	(1,137,871		)
	$	668,464		$	1,214,302

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

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QUICKSILVER RESOURCES INC. (DEBTOR IN POSSESSION)

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

In thousands – Unaudited



	Quicksilver Resources Inc. Stockholders’ Equity
	Common Stock		Additional Paid-in Capital		Treasury Stock			Accumulated Other Comprehensive Income			Retained Earnings (Deficit)			Total
Balances at December 31, 2013	$	1,840	$	770,092	$	(51,422	)	$	109,881		$	(1,836,361	)	$	(1,005,970	)
Net loss	—		—		—			—			(71,171		)	(71,171		)
Hedge derivative contract settlements reclassified into production revenue from AOCI, net of income tax of $8,455	—		—		—			(20,939		)	—			(20,939		)
Foreign currency translation adjustment	—		—		—			(6,162		)	—			(6,162		)
Issuance and vesting of stock compensation	32		9,114		(2,388		)	—			—			6,758
Balances at September 30, 2014	$	1,872	$	779,206	$	(53,810	)	$	82,780		$	(1,907,532	)	$	(1,097,484	)

Balances at December 31, 2014	$	1,878	$	781,669	$	(53,810	)	$	71,853		$	(1,939,461	)	$	(1,137,871	)
Net loss	—		—		—			—			(471,718		)	(471,718		)
Hedge derivative contract settlements reclassified into production revenue from AOCI, net of income tax of $6,047	—		—		—			(17,553		)	—			(17,553		)
Foreign currency translation adjustment	—		—		—			(5,996		)	—			(5,996		)
Issuance and vesting of stock compensation	37		5,114		(115		)	—			—			5,036
Balances at September 30, 2015 (Restated)	$	1,915	$	786,783	$	(53,925	)	$	48,304		$	(2,411,179	)	$	(1,628,102	)

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

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QUICKSILVER RESOURCES INC. (DEBTOR IN POSSESSION)

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

In thousands – Unaudited



	For the Nine Months Ended September 30,
	2015			2014
	(Restated)
Operating activities:
Net loss	$	(471,718	)	$	(71,171	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depletion, depreciation and accretion	39,793			42,584
Impairment expense	241,929			135
Deferred income tax expense	6,047			8,455
Hedging and derivative activities	122,111			6,731
Stock-based compensation	5,151			9,146
Non-cash interest expense	3,897			8,441
Reorganization items, net	133,683			—
Fortune Creek accretion	9,877			11,605
Other	(66		)	(347		)
Changes in assets and liabilities
Accounts receivable	35,218			(1,936		)
Prepaid expenses and other assets	(7,991		)	1,747
Accounts payable	(6,101		)	(12,472		)
Income taxes	(19		)	(432		)
Accrued and other liabilities	58			(7,469		)
Net cash provided by (used in) operating activities	111,869			(4,983		)
Investing activities:
Capital expenditures	(25,007		)	(111,444		)
Proceeds from Southwestern Transaction	—			95,587
Proceeds from sale of properties and equipment	2,978			1,942
Purchases of marketable securities	—			(55,890		)
Maturities and sales of marketable securities	—			222,025
Net cash provided by (used in) investing activities	(22,029		)	152,220
Financing activities:
Issuance of debt	28,335			243,184
Repayments of debt	(170,660		)	(193,689		)
Debt issuance costs paid	(80		)	(225		)
Distribution of Fortune Creek Partnership funds	(1,426		)	(37,113		)
Purchase of treasury stock	(115		)	(2,388		)
Net cash provided by (used in) financing activities	(143,946		)	9,769
Effect of exchange rate changes in cash	6,250			2,216
Net change in cash and cash equivalents	(47,856		)	159,222
Cash and cash equivalents at beginning of period	223,529			89,103
Cash and cash equivalents at end of period	$	175,673		$	248,325

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

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QUICKSILVER RESOURCES INC. (DEBTOR IN POSSESSION)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited

1. CHAPTER 11 PROCEEDINGS AND ACCOUNTING POLICIES

Chapter 11 Proceedings

On March 17, 2015, the Company and our subsidiaries Barnett Shale Operating LLC, Cowtown Drilling, Inc., Cowtown Gas Processing L.P., Cowtown Pipeline Funding, Inc., Cowtown Pipeline L.P., Cowtown Pipeline Management, Inc., Makarios Resources International Holdings LLC, Makarios Resources International Inc., QPP Holdings LLC, QPP Parent LLC, Quicksilver Production Partners GP LLC, Quicksilver Production Partners LP, and Silver Stream Pipeline Company LLC each filed a voluntary petition under Chapter 11 in the Bankruptcy Court to restructure our obligations and capital structure. The Chapter 11 cases are being jointly administered for procedural purposes only by the Bankruptcy Court under the caption In re Quicksilver Resources Inc., et. al., Case No. 15-10585 (LSS) (Jointly Administered).

The U.S. Debtors are currently operating our business as debtors in possession in accordance with the applicable provisions of the Bankruptcy Code. Since the Chapter 11 filings, the Bankruptcy Court has entered the orders necessary to enable the U.S. Debtors to conduct normal business activities, including orders to, among other things and subject to applicable caps for pre-petition items, pay employee wages and benefits, pay certain lienholders and critical vendors, and forward funds belonging to third parties, including royalty holders and partners, as well as the approval of the U.S. Debtors’ use of their secured lenders’ cash collateral and collateral, and the provision of adequate protection related thereto. The order authorizing the U.S. Debtors to use collateral and cash collateral will expire on December 17, 2015. The U.S. Debtors will be seeking and expect to receive authority to use collateral and cash collateral beyond December 17, 2015. While the U.S. Debtors are subject to Chapter 11, all transactions outside the ordinary course of their business will require the prior approval of the Bankruptcy Court.

On March 16, June 15 and September 15, 2015, we, along with QRCI, entered into the Forbearance Agreements with the administrative agents and certain of the lenders under the Combined Credit Agreements. As a result of the Chapter 11 filing, the obligations under the Combined Credit Agreements were automatically accelerated. However, pursuant to the Forbearance Agreements, the administrative agents and the lenders agreed to, among other things, (i) forbear from exercising their rights and remedies in connection with specified defaults under the Amended and Restated Canadian Credit Facility related to our Chapter 11 filing until the earlier of December 15, 2015 or certain other events specified in the Forbearance Agreements, including, among other things, the commencement by QRCI or certain specified Canadian subsidiary guarantors of insolvency proceedings and (ii) waive compliance with certain specified terms and conditions relating to the renewal of outstanding evergreen letters of credit under the Combined Credit Agreements, among other things.

On September 17, 2015, the Company announced the commencement of a marketing and sale process to sell substantially all or a portion of its U.S. and Canadian assets. The U.S. process was initiated with the filing of a motion with the Bankruptcy Court seeking approval of bidding procedures to commence a sale process for the Company’s U.S. assets under Bankruptcy Code section 363. On October 6, 2015, the Bankruptcy Court entered an order approving the Company’s proposed bidding procedures in their entirety. Pursuant to the Bankruptcy Court’s order, the deadline for interested parties to submit a bid to purchase some or substantially all of the Company’s U.S. assets is November 30, 2015 at 5:00 p.m. (ET) and an auction will be conducted with respect to bids received by qualified bidders on December 9, 2015 at 10:00 a.m. (CT) followed by a hearing to approve one or more sales to successful bidders to be held on December 14, 2015 at 10:00 a.m. (ET). The Canadian process, which is an out of court process and will run in parallel to the process approved by the Bankruptcy Court for the U.S. assets, was also launched on September 17, 2015. Both the U.S. and the Canadian processes will be conducted with the assistance of Houlihan Lokey. There can be no assurances that the marketing and sale process will be successful.

Appointment of Creditors Committee. On March 25, 2015, the United States Trustee for Delaware appointed the Creditors Committee. The Creditors Committee and its legal representatives have a right to be heard on all matters that come before the Bankruptcy Court with respect to the U.S. Debtors. There can be no assurance that the Creditors Committee will support the U.S. Debtors’ positions on matters presented to the Bankruptcy Court, including any Chapter 11 plan. Disagreements between the U.S. Debtors and the Creditors Committee could

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protract the Chapter 11 proceedings, negatively impact the U.S. Debtors’ ability to operate, and delay the U.S. Debtors’ emergence from the Chapter 11 proceedings.

The U.S. Debtors’ Exclusivity Periods. On July 7, 2015, the Bankruptcy Court entered an order extending the U.S Debtors’ (i) Exclusive Filing Period through and including October 13, 2015 and (ii) Exclusive Solicitation Period through and including December 14, 2015. On October 13, 2015, the U.S. Debtors requested extensions of the Exclusive Filing Period and Exclusive Solicitation Period through and including February 1, 2016, and April 13, 2016, respectively, to afford them the opportunity to complete the critical tasks necessary to develop and negotiate a Chapter 11 plan with their creditors. The Exclusive Filing Period is automatically extended until the Bankruptcy Court acts on this request, and a hearing on the matter is scheduled on November 3, 2015.

Rejection of Executory Contracts. Subject to certain exceptions, under the Bankruptcy Code, the U.S. Debtors may assume, assign, or reject certain executory contracts and unexpired leases subject to the approval of the Bankruptcy Court and certain other conditions. The rejection of an executory contract or unexpired lease is generally treated as a pre-petition breach of such executory contract or unexpired lease and, subject to certain exceptions, relieves the U.S. Debtors of performing their future obligations under such executory contract or unexpired lease but entitles the contract counterparty or lessor to a pre-petition general unsecured claim for damages caused by such deemed breach. Counterparties to such rejected contracts or leases may assert claims against the applicable U.S. Debtor's estate for such damages. The assumption of an executory contract or unexpired lease generally requires the U.S. Debtors to cure existing monetary defaults under such executory contract or unexpired lease and provide adequate assurance of future performance. Accordingly, any description of an executory contract or unexpired lease with the U.S. Debtors in this Quarterly Report, including where applicable a quantification of our obligations under any such executory contract or unexpired lease with the U.S. Debtors, is qualified by any overriding rejection rights we have under the Bankruptcy Code. Further, nothing herein is or shall be deemed an admission with respect to any claim amounts or calculations arising from the rejection of any executory contract or unexpired lease and the U.S. Debtors expressly preserve all of their rights with respect thereto.

The U.S. Debtors’ financial statements include amounts classified as Liabilities Subject to Compromise that the U.S. Debtors believe the Bankruptcy Court will allow as claim amounts resulting from the U.S. Debtors’ rejection of various executory contracts and unexpired leases. Additional amounts may be included in Liabilities Subject to Compromise in future periods if additional executory contracts and unexpired leases are rejected. Conversely, the U.S. Debtors expect that the assumption of certain executory contracts and unexpired leases may convert certain liabilities shown in future financial statements as subject to compromise to post-petition liabilities. Due to the uncertain nature of many of the potential claims, the magnitude of such claims is not reasonably estimable at this time. Such claims may be material (see “Liabilities Subject to Compromise” below).

Magnitude of Potential Claims. On June 9, 2015, the U.S. Debtors filed with the Bankruptcy Court Schedules and Statements setting forth, among other things, the assets and liabilities of the U.S. Debtors, subject to the assumptions filed in connection therewith. The Schedules and Statements may be subject to further amendment or modification. On October 14, 2015, the U.S. Debtors filed an amended schedule with the Bankruptcy Court to add certain executory contracts to the schedule.

Certain holders of pre-petition claims were required to file proofs of claim by the Bar Date. As of October 27, 2015, approximately 498 claims totaling about $14.6 billion had been filed with the Bankruptcy Court against the U.S. Debtors, and we expect amended claims to be filed in the future, including claims amended to assign values to claims originally filed with no designated value. Through the claims resolution process, we have identified, and we expect to continue to identify, claims that we believe should be disallowed by the Bankruptcy Court because they are duplicative, have been later amended or superseded, are without merit, are overstated or for other reasons. We have and will file objections with the Bankruptcy Court as necessary for claims we believe should be disallowed. Claims we believe are allowable are included in Liabilities Subject to Compromise.

Through the claims resolution process, differences in amounts scheduled by the U.S. Debtors and claims filed by creditors will be investigated and resolved, including through the filing of objections with the Bankruptcy Court where appropriate. The claims resolution process will take additional time to complete, and we expect that it will continue after our emergence from bankruptcy. Accordingly, the ultimate number and amount of allowed claims is not presently known, nor can the ultimate recovery with respect to allowed claims be presently ascertained.

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Costs of Reorganization. The U.S. Debtors have incurred and will continue to incur significant costs associated with the reorganization. The amount of these costs, which are being expensed as incurred, are expected to significantly affect our results of operations and liquidity. For additional information, see “Reorganization Items, net” below.

Effect of Filing on Creditors and Stockholders. Under the priority scheme established by the Bankruptcy Code, unless creditors agree otherwise, pre-petition liabilities and post-petition liabilities must be satisfied in full before the holders of our existing common stock are entitled to receive any distribution or retain any property under a Chapter 11 plan. The ultimate recovery to creditors and/or stockholders, if any, will not be determined until confirmation and implementation of Chapter 11 plan. No assurance can be given as to what values, if any, will be ascribed in the Chapter 11 proceedings to each of these constituencies or what types or amounts of distributions, if any, they would receive. A Chapter 11 plan could result in holders of U.S. Debtors’ liabilities and/or securities, including our common stock, receiving no distribution on account of their interests and cancellation of their holdings. We believe that it is highly likely that the shares of our existing common stock will be canceled in the Chapter 11 proceedings and will be entitled to a limited recovery, if any. As discussed below, if certain requirements of the Bankruptcy Code are met, a Chapter 11 plan can be confirmed notwithstanding its rejection by the holders of our common stock and notwithstanding the fact that such holders do not receive or retain any property on account of their equity interests under the plan. Because of such possibilities, the value of our securities, including our common stock, is highly speculative. We urge that appropriate caution be exercised with respect to existing and future investments in any of the securities of the U.S. Debtors.

Subject to certain specific exceptions under the Bankruptcy Code, the Chapter 11 filings automatically enjoined, or stayed, the continuation of any judicial or administrative proceedings or other actions against the U.S. Debtors or their property to recover on, collect or secure a claim arising prior to the Petition Date. As a result, for example, most creditor actions to obtain possession of property from the U.S. Debtors, or to create, perfect or enforce any lien against the property of the U.S. Debtors, or to collect on or otherwise exercise rights or remedies with respect to a pre-petition claim are enjoined unless and until the Bankruptcy Court lifts the automatic stay.

Notice and Hearing Procedures for Trading in Claims and Equity Securities. The Bankruptcy Court issued a final order pursuant to Sections 105(a), 362(a)(3) and 541 of the Bankruptcy Code to enable the U.S. Debtors to avoid limitations on the use of their tax net operating loss carryforwards and certain other tax attributes by imposing certain notice procedures and transfer restrictions on the trading of our equity securities.

In general, the order applies to any person or entity that, directly or indirectly, beneficially owns (or would beneficially own as a result of a proposed transfer) at least 4.75% of our outstanding equity securities. Substantial Equityholders are required to file with the Bankruptcy Court and serve us with notice of such status. In addition, the order provides that a person or entity that would become a Substantial Equityholder by reason of a proposed acquisition of our equity securities is also required to comply with the notice and service provisions before effecting that transaction. The order gives the U.S. Debtors the right to seek an injunction from the Bankruptcy Court to prevent certain acquisitions or sales of our common stock if the acquisition or sale would pose a material risk of adversely affecting our ability to utilize such tax attributes.

Under the order, prior to any proposed acquisition of equity securities that would result in an increase in the amount of our equity securities owned by a Substantial Equityholder, or that would result in a person or entity becoming a Substantial Equityholder, such person, entity or Substantial Equityholder is required to file with the Bankruptcy Court, and serve on the Company, a Notice of Intent to Purchase, Acquire or Otherwise Accumulate an Equity Security. In addition, prior to effecting any disposition of our equity securities that would result in a decrease in the amount of our equity securities beneficially owned by a Substantial Equityholder, such Substantial Equityholder is required to file with the Bankruptcy Court, and serve on the Company, a Notice of Intent to Sell, Trade or Otherwise Transfer Equity Securities.

Any purchase, sale or other transfer of our equity securities in violation of the restrictions of the order would be null and void ab initio as an act in violation of such order and would therefore confer no rights on a proposed transferee.

Process for Chapter 11 plan. In order to successfully exit bankruptcy, the U.S. Debtors will need to propose, and obtain confirmation by the Bankruptcy Court of, a plan (or plans) that satisfies the requirements of the Bankruptcy Code. A Chapter 11 plan would, among other things, resolve the U.S. Debtors’ pre-petition

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obligations, set forth the revised capital structure of the newly reorganized entity and provide for corporate governance subsequent to exit from bankruptcy.

The U.S. Debtors have the exclusive right for 120 days after the Petition Date to file a Chapter 11 plan and have been granted a 90 day extension to the Exclusive Periods. As discussed above, the U.S. Debtors have requested a further extension of the Exclusive Periods. If we file a Chapter 11 plan, the U.S. Debtors have 60 additional days to obtain necessary acceptances of our plan. The periods may be further extended by the Bankruptcy Court for cause. If the U.S. Debtors’ Exclusive Filing Period lapses, any party in interest may file a Chapter 11 plan for any of the U.S. Debtors. As discussed above, the Exclusive Filing Period has been automatically extended until the Bankruptcy Court acts on the U.S. Debtors’ request to further extend the Exclusive Filing Period and Exclusive Solicitation Period through and including February 1, 2016, and April 13, 2016, respectively, and a hearing on the matter is scheduled on November 3, 2015.

In addition to being voted on by holders of impaired claims and equity interests, a Chapter 11 plan must satisfy certain requirements of the Bankruptcy Code and must be approved, or confirmed, by the Bankruptcy Court in order to become effective. A Chapter 11 plan would be accepted by holders of claims against and equity interests in the U.S. Debtors if (i) at least one-half in number and two-thirds in dollar amount of claims actually voting in each class of claims impaired by the plan have voted to accept the plan and (ii) at least two-thirds in amount of equity interests actually voting in each class of equity interests impaired by the plan has voted to accept the plan. A class of claims or equity interests that does not receive or retain any property under the plan on account of such claims or interests is deemed to have voted to reject the plan.

Under certain circumstances set forth in Section 1129(b) of the Bankruptcy Code, the Bankruptcy Court may confirm a plan even if such plan has not been accepted by all impaired classes of claims and equity interests. The precise requirements and evidentiary showing for confirming a plan notwithstanding its rejection by one or more impaired classes of claims or equity interests depends upon a number of factors, including the status and seniority of the claims or equity interests in the rejecting class (i.e., secured claims or unsecured claims, subordinated or senior claims, preferred or common stock). Generally, with respect to common stock interests, a plan may be “crammed down” even if the shareowners receive no recovery if the proponent of the plan demonstrates that (1) no class junior to the common stock is receiving or retaining property under the plan and (2) no class of claims or interests senior to the common stock is being paid more than in full.

The timing of filing a Chapter 11 plan by the U.S. Debtors will depend on the timing and outcome of numerous other ongoing matters in the Chapter 11 proceedings. There can be no assurance at this time that the U.S. Debtors will be able to successfully develop, confirm and consummate one or more Chapter 11 plans that satisfies the conditions of the Bankruptcy Code and is confirmed by the Bankruptcy Court, or that any such plan will be implemented successfully.

For the duration of our Chapter 11 proceedings, our operations and our ability to develop and execute our business plan are subject to the risks and uncertainties associated with the Chapter 11 process as described in our 2014 Annual Report on Form 10-K, Item 1A, “Risk Factors.” As a result of these risks and uncertainties, the number of our outstanding shares and our stockholders, assets, liabilities, officers and/or directors could be significantly different following the outcome of the Chapter 11 proceedings, and the description of our operations, properties and capital plans included in this Quarterly Report may not accurately reflect our operations, properties and capital plans following the Chapter 11 process.

Basis of Presentation

The accompanying condensed consolidated interim financial statements have not been audited. In management’s opinion, the accompanying condensed consolidated interim financial statements contain all adjustments necessary to fairly present our financial position as of September 30, 2015 and our results of operations and cash flows for the periods presented. All such adjustments are of a normal recurring nature unless otherwise noted. The results for interim periods are not necessarily indicative of annual results.

The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expense during each reporting period. We believe our estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties, which may cause actual results to differ materially from management’s estimates.

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Certain disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted. Accordingly, these financial statements should be read in conjunction with our consolidated financial statements and notes thereto included in our 2014 Annual Report on Form 10-K.

As a result of sustained losses and our Chapter 11 proceedings, the realization of assets and satisfaction of liabilities, without substantial adjustments and/or changes in ownership, are subject to uncertainty. Given the uncertainty surrounding our Chapter 11 proceedings, there is substantial doubt about our ability to continue as a going concern.

The accompanying condensed consolidated interim financial statements do not purport to reflect or provide for the consequences of our Chapter 11 proceedings, other than as set forth under Liabilities Subject to Compromise and Reorganization Items, net on the accompanying condensed consolidated interim financial statements. In particular, the financial statements do not purport to show (i) as to assets, their realizable value on a liquidation basis or their availability to satisfy liabilities; (ii) as to pre-petition liabilities, the amounts that may be allowed for claims or contingencies, or the status and priority thereof; (iii) as to stockholders’ equity accounts, the effect of any changes that may be made in our capitalization; or (iv) as to operations, the effect of any changes that may be made to our business.

In accordance with GAAP, we have applied ASC 852 “Reorganizations,” in preparing our condensed consolidated interim financial statements. ASC 852 requires that the financial statements, for periods subsequent to the Chapter 11 filing, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain revenues, expenses, realized gains and losses and provisions for losses that are realized or incurred in the bankruptcy proceedings are recorded in Reorganization Items, net in the accompanying condensed consolidated statements of income (loss) and comprehensive income (loss). In addition, pre-petition obligations that may be impacted by the bankruptcy reorganization process have been classified on our condensed consolidated balance sheets at September 30, 2015 in Liabilities Subject to Compromise. These liabilities are reported at the amounts expected to be allowed by the Bankruptcy Court, even if they may be settled for lesser amounts.

While operating as debtors in possession under Chapter 11 of the Bankruptcy Code, the U.S. Debtors may sell or otherwise dispose of or liquidate assets or settle liabilities in amounts other than those reflected in our condensed consolidated interim financial statements, subject to the approval of the Bankruptcy Court or otherwise as permitted in the ordinary course of business. Further, a Chapter 11 plan could materially change the amounts and classifications in our historical condensed consolidated interim financial statements.

Liabilities Subject to Compromise

The following table summarizes the components of liabilities subject to compromise included on our Condensed Consolidated Balance Sheet as of September 30, 2015:



	September 30, 2015

	(in thousands)
Accounts payable	$	1,215
Accrued liabilities	116,515
Debt	1,766,398
Liabilities subject to compromise	$	1,884,128

Liabilities Subject to Compromise refers to pre-petition obligations that may be impacted by the Chapter 11 reorganization process. The amounts represent our current estimate of known or potential obligations to be resolved in connection with our Chapter 11 proceedings. Accrued liabilities primarily includes previously accrued and unpaid interest that is associated with the debt that we believe may be impacted by the bankruptcy reorganization process.

Differences between liabilities we have estimated and the claims filed, will be investigated and resolved in connection with the claims resolution process. We will continue to evaluate these liabilities throughout the Chapter 11 process and adjust amounts as necessary. Such adjustments may be material.

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Reorganization Items, net

The following table summarizes the components included in Reorganization Items, net in our condensed consolidated statements of income (loss) and comprehensive income (loss) for the three and nine months ended September 30, 2015:



	For the Three Months Ended September 30, 2015			For the Nine Months Ended September 30, 2015

	(in thousands)
Professional fees	$	8,352		$	22,895
Deferred financing costs and unamortized discounts	—			59,983
Deferred interest rate swap gains	—			(2,314		)
Terminated contracts	(469		)	68,004
Reorganization items, net	$	7,883		$	148,568

Professional fees included in Reorganization Items, net are for post-petition expenses. Deferred financing costs and unamortized discounts are included for the Second Lien Term Loan, Second Lien Notes, Senior Notes due 2019, Senior Notes due 2021 and Senior Subordinated Notes as we believe these debt instruments may be impacted by the bankruptcy reorganization process. Terminated contracts represent the estimated claims related to five GPT and one professional fee contracts that run through 2019 and were not previously included on the balance sheet as the liability was contingent or an executory contract included in commitments and contingencies. The amount is derived by using the undiscounted contractual rates multiplied by the remaining contractual volumes and will be adjusted through the claims reconciliation process as necessary. The reduction in terminated contracts for the three months ended September 30, 2015 is due to an adjustment to the previously accrued amount based on claims filed.

Recently Issued Accounting Standards

In February 2015, the FASB issued accounting guidance, “Consolidation (Topic 810): Amendments to the Consolidation Analysis,” requiring reporting entities to evaluate whether they should consolidate certain legal entities. The standard is effective for us in the first quarter of 2016 with early adoption permitted. We are currently evaluating the new guidance and have not determined the impact this standard may have on our financial statements.

In April 2015, the FASB issued accounting guidance, “Interest - Imputation of Interest,” that requires debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. This update is effective for us in the first quarter of 2016. We will adopt this guidance in the first quarter of 2016 which will reduce other assets and the current portion of long-term debt.

In July 2015, the FASB voted to extend by one year the effective date to adopt the accounting guidance, “Revenue from Contracts with Customers,” which requires an entity to recognize the amount of revenue that it expects to be entitled for the transfer of promised goods or services to customers. The updated standard will replace most existing revenue recognition guidance in U.S. GAAP when it becomes effective and permits the use of either the retrospective or cumulative effect transition method. Reporting entities may elect to adopt the guidance at the original effective date or may delay one year. We intend to delay the adoption of this guidance until the first quarter of 2018. We have not yet selected a transition method and we are currently evaluating the effect, if any, that the updated standard will have on our consolidated financial statements and related disclosures.

In July 2015, the FASB issued accounting guidance, “Simplifying the Measurement of Inventory,” that requires inventory to be measured at the lower of cost and net realizable value and options that currently exist for market value to be eliminated. The guidance defines net realizable value as the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. The guidance is effective on a prospective basis for reporting periods beginning after December 15, 2016 and interim periods within those fiscal years with early adoption permitted. We are evaluating the impact that the adoption will have on our consolidated financial statements.

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No other pronouncements materially affecting our financial statements have been issued since the filing of our 2014 Annual Report on Form 10-K.

Restatement of Previously Reported Consolidated Financial Statements

Subsequent to filing our Form 10-Q for the period ended September 30, 2015, we identified an error in the calculation of our crude oil and natural gas proved reserve estimates as of September 30, 2015. The reserve estimate error resulted in an understatement of impairment expense for the nine months ended September 30, 2015. The reserve estimate error was due to all applicable costs not being considered.

On March 8, 2016 management and the audit committee of our Board of Directors concluded that adjustment to the historical financial statements was required; therefore, we restated our condensed consolidated balance sheet as of September 30, 2015 and the related statement of income and comprehensive income, statement of stockholders’ equity and statement of cash flows for the three and nine months ended September 30, 2015 on Form 10-Q/A. These adjustments to the financial statements represent additional non-cash impairment charges.

The following tables show the effects of the adjustments made to our Condensed Consolidated Balance Sheets as of September 30, 2015 and Condensed Consolidated Statements of Income (Loss) and Comprehensive Income (Loss) and Condensed Consolidated Statements of Cash Flows for the three months and nine months ended September 30, 2015.

Condensed Consolidated Balance Sheets



	As of September 30, 2015
	Previously Reported			Adjustments		As Restated

	(in thousands)
Oil and natural gas properties, full cost method	$	403,248		(61,760	)	$	341,488
Property, plant and equipment - net	502,580			(61,760	)	440,820
Total assets	730,224			(61,760	)	668,464
Retained deficit	(2,349,419		)	(61,760	)	(2,411,179		)
Total stockholders' equity	(1,566,342		)	(61,760	)	(1,628,102		)
Total liabilities and stockholders' equity	730,224			(61,760	)	668,464

Condensed Consolidated Statements of Income (Loss) and Comprehensive Income (Loss)



	For the Three Months Ended September 30, 2015									For the Nine Months Ended September 30, 2015
	Previously Reported			Adjustments			As Restated			Previously Reported			Adjustments			As Restated

	(in thousands), except for per share data
Impairment	$	102,758		$	61,760		$	164,518		$	180,169		$	61,760		$	241,929
Total expense	164,274			61,760			226,034			403,153			61,760			464,913
Operating income (loss)	(105,287		)	(61,760		)	(167,047		)	(176,034		)	(61,760		)	(237,794		)
Income (loss) before income taxes	(120,300		)	(61,760		)	(182,060		)	(404,122		)	(61,760		)	(465,882		)
Net income (loss)	(122,452		)	(61,760		)	(184,212		)	(409,958		)	(61,760		)	(471,718		)
Comprehensive income (loss)	(128,111		)	(61,760		)	(189,871		)	(433,507		)	(61,760		)	(495,267		)
Earnings (loss) per common share - basic	$	(0.69	)	$	(0.36	)	$	(1.05	)	$	(2.33	)	$	(0.35	)	$	(2.68	)
Earnings (loss) per common share - diluted	$	(0.69	)	$	(0.36	)	$	(1.05	)	$	(2.33	)	$	(0.35	)	$	(2.68	)

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Condensed Consolidated Statements of Cash Flows



	For the nine months ended September 30, 2015
	Previously Reported			Adjustments		As Restated

	(in thousands)
Net loss	$	(409,958	)	(61,760	)	$	(471,718	)
Impairment expense	180,169			61,760		241,929

There was no effect on the total net cash provided by operating activities included in the condensed consolidated statement of cash flows for the nine months ended September 30, 2015.

2. DIVESTITURES

In May 2014, we completed the sale of our Niobrara Asset to Southwestern Energy Company. The purchase price was subject to customary purchase price adjustments, which resulted in Southwestern paying us $95.6 million, including a final adjustment of $2.1 million, which we received in the third quarter of 2014. We determined that the Southwestern Transaction did not represent a significant disposal of reserves under GAAP, therefore we reduced the balance of U.S. oil and gas properties by the amount of these proceeds and we did not recognize a gain or loss.

Note 3 to the consolidated financial statements in our 2014 Annual Report on Form 10-K contains additional information on other divestitures.

3. DERIVATIVES AND FAIR VALUE MEASUREMENTS

The following table categorizes our commodity derivative instruments based upon the level of the inputs used in estimating the fair value:



	Asset Derivatives				Liability Derivatives
	September 30, 2015		December 31, 2014		September 30, 2015		December 31, 2014

	(in thousands)				(in thousands)
Level 2 derivative instruments	$	—	$	104,608	$	—	$	—
Level 3 derivative instruments	—		44,959		—		—
Total	$	—	$	149,567	$	—	$	—

The fair value of “Level 2” derivative instruments included in these disclosures was estimated using inputs quoted in active markets for the periods covered by the derivatives. The fair value of derivative instruments designated as “Level 3” at December 31, 2014, was estimated using prices quoted in markets where there is insufficient market activity for consideration as “Level 2” instruments. At December 31, 2014, only our natural gas derivatives with an original tenure of 10 years utilized “Level 3” inputs, primarily due to comparatively less market data available for the later portion of their term compared with our other shorter term derivatives. The fair value of both the “Level 2” and the “Level 3” assets and liabilities are determined using a discounted cash flow model using the terms of the derivative instrument, market prices for the periods covered by the derivatives, and the credit adjusted risk-free interest rates. The “Level 3” unobservable input at December 31, 2014 was the market prices for natural gas for the period from 2019 to 2021, as there is not an active market for that period of time. These unobservable inputs included within the fair value calculation range at December 31, 2014 from $2.88 to $4.60 and are based upon prices quoted in active markets for the period of time available. A decrease of these unobservable inputs would increase the fair value, while an increase would decrease the fair value.

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The following table identifies the changes in “Level 3” net asset derivative fair values for the periods indicated:



	For the Three Months Ended September 30,
	2015		2014

	(in thousands)
Balance at beginning of period	$	—	$	(5,533	)
Total gains (losses) for the period:
Unrealized gain on derivatives	—		24,829
Settlements in net derivative gains (losses)	—		(1,542		)
Balance at end of period	$	—	$	17,754

Total gains included in net derivative gains (losses) attributable to the change in unrealized gains related to assets still held at the reporting date	$	—	$	24,485



	For the Nine Months Ended September 30,
	2015			2014

	(in thousands)
Balance at beginning of period	$	44,959		$	23,485
Total gains (losses) for the period:
Unrealized loss on derivatives	(109,240		)	(6,488		)
Settlements in net derivative gains (losses)	64,281			757
Balance at end of period	$	—		$	17,754

Total losses included in net derivative gains (losses) attributable to the change in unrealized losses related to assets still held at the reporting date	$	—		$	(2,476	)

Commodity Price Derivatives

In 2015, all of our derivatives were terminated either by us or the counterparties to such derivatives in anticipation or as a result of our Chapter 11 filings or through negotiations during the Chapter 11 proceedings. We no longer have any derivatives. The cash proceeds from derivatives terminated in 2015 were $138.9 million.

Effective December 31, 2012, we discontinued the use of hedge accounting. Changes in value subsequent to this date are recognized in net derivative gains (losses) in the period in which they occur. The net deferred hedge gain that was included in AOCI as of December 31, 2012 is being released into revenue from natural gas, NGL and oil production over the original term of the hedging relationship (through 2021). Gains from the effective portion of derivative assets and liabilities held in AOCI expected to be reclassified into earnings during the following twelve months will result in production revenue of $12.4 million net of income taxes.

Interest Rate Derivatives

In 2010, we executed early settlements of our interest rate swaps that were designated as fair value hedges. Upon the early settlements, we recorded the resulting gain as a fair value adjustment to our debt and began to recognize the deferred gain as a reduction of interest expense over the lives of the respective notes. During the nine months ended September 30, 2015 and 2014, we recognized $0.5 million and $1.5 million, respectively, of those deferred gains as a reduction of interest expense. As a result of the Chapter 11 proceedings, the remainder of the deferred gains related to these interest rate swaps were included in Reorganization Items, net.

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Fair Value Disclosures

The estimated fair value of our derivative instruments at September 30, 2015 and December 31, 2014 were as follows:



	Asset Derivatives				Liability Derivatives
	September 30, 2015		December 31, 2014		September 30, 2015		December 31, 2014

	(in thousands)				(in thousands)
Derivatives not designated as hedges:
Commodity contracts reported in:
Current derivative assets	$	—	$	120,176	$	—	$	—
Noncurrent derivative assets	—		81,187		—		51,796
Total derivatives not designated as hedges	$	—	$	201,363	$	—	$	51,796

Derivative assets and liabilities shown in the table above are presented as gross assets and liabilities, without regard to master netting arrangements, which are considered in the presentation of derivative assets and liabilities in the accompanying condensed consolidated balance sheets. The change in carrying value of our commodity price derivatives since December 31, 2014 resulted from the termination of all of our derivatives.

Financial instruments not carried at fair value

Carrying values and fair values of financial instruments that are not carried at fair value in the consolidated balance sheets as of September 30, 2015 and December 31, 2014 are included in Note 5.

4. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consisted of the following:



	September 30, 2015			December 31, 2014

	(in thousands)
	(Restated)
Oil and gas properties
Subject to depletion	$	5,687,844		$	5,821,167
Unevaluated costs	21,377			18,803
Accumulated depletion	(5,367,733		)	(5,225,302		)
Net oil and gas properties	341,488			614,668
Other property and equipment
Pipelines and processing facilities	293,859			316,013
General properties	63,288			66,455
Accumulated depreciation	(257,815		)	(268,356		)
Net other property and equipment	99,332			114,112
Property, plant and equipment, net of accumulated depletion and depreciation	$	440,820		$	728,780

Ceiling Test Analysis and Impairment

We recorded impairment expense of $150.8 million at September 30, 2015 for our U.S. oil and gas properties and $13.7 million and $77.4 million at September 30, 2015 and June 30, 2015, respectively, for our Canadian oil and gas properties. We computed the September 30, 2015 ceiling amount for our U.S. oil and gas properties using the Henry Hub natural gas price of $3.06 per MMBtu of natural gas, calculated as the unweighted average of the preceding 12-month first-day-of-the-month prices. The Henry Hub natural gas price used to compute the ceiling amount at September 30, 2015 was 30% lower than the comparable price at December 31,

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2014. We computed the September 30, 2015 and June 30, 2015 ceiling amounts for our Canadian oil and gas properties using AECO prices of $2.51 and $2.90 per MMBtu of natural gas, respectively, calculated as the unweighted average of the preceding 12-month first-day-of-the-month prices. The AECO natural gas prices used to compute the ceiling amount at September 30, 2015 and June 30, 2015 were 41% and 31% lower, respectively, than the comparable price used at December 31, 2014.

Notes 2 and 7 to the consolidated financial statements in our 2014 Annual Report on Form 10-K contain additional information regarding our property, plant and equipment and our quarterly ceiling test analysis.

5. DEBT

Debt consisted of the following:



	September 30, 2015			December 31, 2014

	(in thousands)
Combined Credit Agreements	$	156,985		$	274,514
Second Lien Term Loan, net of unamortized discount ⁽¹⁾	—			610,242
Second Lien Notes due 2019, net of unamortized discount ⁽¹⁾	—			195,277
Senior notes due 2019, net of unamortized discount ⁽¹⁾	—			293,919
Senior notes due 2021, net of unamortized discount ⁽¹⁾	—			310,590
Senior subordinated notes due 2016 ⁽¹⁾	—			350,000
Total debt	156,985			2,034,542
Unamortized deferred gain-terminated interest rate swaps ⁽¹⁾	—			2,763
Current portion of long-term debt ⁽²⁾	(156,985		)	(2,037,305		)
Long-term debt ⁽²⁾	$	—		$	—


⁽¹⁾	Classified as Liability Subject to Compromise as of September 30, 2015


⁽²⁾	As a result of our Chapter 11 filings, we have classified all debt as current at September 30, 2015

In March 2015, a third-party service provider drew down the full face amount of a C$33 million letter of credit in connection with the termination of a Canadian gathering and processing contract. See additional discussion in Note 7. In April and May 2015, other third-party service providers in the U.S. drew down $2.1 million of outstanding letters of credit.

As of September 30, 2015, $157.0 million in loans ($78.6 million and $78.4 million in the U.S. and Canada, respectively) and $9.7 million ($7.7 million and $2.0 million in the U.S. and Canada, respectively) in letters of credit were outstanding under our Combined Credit Agreements. Our Chapter 11 filings constituted an event of default under the Combined Credit Agreements and all borrowings and other fees under the Combined Credit Agreements became immediately due and payable. As a result, we no longer have any liquidity available to us under the Combined Credit Agreements. The ability of the lenders under the Combined Credit Agreements to seek remedies to enforce their rights under the agreements against the U.S. Debtors was automatically stayed as a result of the Chapter 11 filings, and the lenders’ rights of enforcement against the U.S. Debtors are subject to the applicable provisions of the Bankruptcy Code. Amounts outstanding under the Combined Credit Agreements have not been included in Liabilities Subject to Compromise because we believe this secured debt will not be impacted by the bankruptcy reorganization process. We continue to accrue and pay interest on the Combined Credit

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Agreements in accordance with the Forbearance Agreement and the Bankruptcy Court’s cash collateral order. Beginning on March 17, 2015, as part of the Forbearance Agreement, we agreed to pay interest monthly for the Amended and Restated U.S. Credit Facility at a specified rate of ABR plus the applicable margin and for the Amended and Restated Canadian Credit Facility at a specified rate of Canadian prime plus the default rate plus the applicable margin for Canadian dollar denominated borrowings, and U.S. prime plus the default rate plus the applicable margin, for U.S. dollar denominated borrowings. Subsequent to the Forbearance Agreement, we agreed in connection with the adequate protection package, which allowed for the use of cash collateral and collateral, to fix the applicable margin for loans under the Amended and Restated U.S. Credit Facility to 2.5%. We also agreed to set the applicable margin for loans under the Amended and Restated Canadian Credit Facility to 2.75%. At September 30, 2015, the weighted average interest rate for amounts outstanding under the Combined Credit Agreement was 6.66%. In April 2015, we repaid $88.0 million ($46.5 million and $41.5 million in the U.S. and Canada, respectively) and in June 2015 and August 2015 we repaid an additional $11.1 million and $3.2 million, respectively, in the U.S., of outstanding amounts under our Combined Credit Agreements with proceeds from terminated derivative positions.

Our Chapter 11 filings also constituted an event of default under the Second Lien Term Loan, the Second Lien Notes, the Senior Notes due 2019, the Senior Notes due 2021, and the Senior Subordinated Notes. All principal, interest and other amounts under each of these debt instruments became immediately due and payable. The ability of the lenders and noteholders to seek remedies to enforce their rights under the applicable debt instruments was automatically stayed as a result of the Chapter 11 filings, and the lenders’ and noteholders’ rights of enforcement are subject to the applicable provisions of the Bankruptcy Code. Amounts outstanding under the Second Lien Term Loan, Second Lien Notes, Senior Notes due 2019, Senior Notes due 2021 and Senior Subordinated Notes have been reclassified as Liabilities Subject to Compromise. We discontinued the accrual of interest on the Second Lien Term Loan, Second Lien Notes, Senior Notes due 2019, Senior Notes due 2021 and Senior Subordinated Notes from and after the Petition Date. However, we are making adequate protection payments to the lenders under the Second Lien Term Loan and the holders of the Second Lien Notes, in each case in an amount equal to all accrued and unpaid post-petition interest (at a rate of 7.00% as of September 30, 2015), fees and costs due and payable on a monthly basis under the Second Lien Term Loan and the indenture for the Second Lien Notes, respectively, in accordance with the Bankruptcy Court’s cash collateral order. As the Bankruptcy Court will ultimately determine the treatment of all amounts subject to compromise and our Second Lien Term Loan and Second Lien Notes may be impacted by the bankruptcy reorganization process, the adequate protection payments are treated as a principal payment rather than as interest expense. The Bankruptcy Court could recharacterize these payments as diminution in value claims or interest payments or find that additional amounts are due, which in each case could require us to expense these payments. As of September 30, 2015 we have made aggregate payments of $31.6 million under the Bankruptcy Court’s cash collateral order.

Summary of All Outstanding Debt

Except where otherwise noted, the following table summarizes certain significant aspects of our long-term debt outstanding immediately prior to the Chapter 11 filings. Upon the Chapter 11 filings, all principal, interest and other amounts under each of the debt instruments governing the long-term debt set forth in the table below was accelerated and became immediately due and payable.

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The information in the table below is presented without regard to the effect of the Chapter 11 filings, except where otherwise noted, and therefore does not take into account the acceleration of the listed debt instruments and other impacts of the Chapter 11 filings.

Priority on Collateral and Structural Seniority ⁽¹⁾

Highest

priority

Lowest

priority

First Lien

Second Lien

Senior Unsecured

Senior Subordinated

Combined Credit
Agreements

Second Lien Term Loan

Second Lien Notes

2019
Senior Notes

2021
Senior Notes

Senior
Subordinated Notes

Principal amount ^{(1) (2)}

$325 million

$625 million

$200 million

$298 million

$325 million

$350 million

Scheduled maturity date prior to acceleration ⁽³⁾

September 6, 2016

June 21, 2019

August 15, 2019

July 1, 2021

April 1, 2016

Springing maturity date prior to acceleration ⁽³⁾

October 2, 2015

January 1, 2016

N/A

Interest rate on outstanding borrowings at September 30, 2015 ⁽⁴⁾

6.66%

7.00%

9.125%

11.00%

7.125%

Base interest rate

options prior to acceleration ^{(5) (6)}

LIBOR, ABR, CDOR

LIBOR floor of 1.25%; ABR floor of 2.25%

LIBOR floor of 1.25%

N/A

Financial covenants ^{(7) (9)}

- Minimum current ratio of 1.0
- Minimum EBITDAX or EBITDA to cash interest expense
- Maximum senior secured debt leverage ratio of 2.0

N/A

Significant restrictive

covenants ^(7)(8)(9)

- Incurrence of debt
- Incurrence of liens
- Payment of dividends
- Equity purchases
- Asset sales
- Affiliate transactions
- Limitations on derivatives and investments

- Incurrence of debt
- Incurrence of liens and 1st lien cap
-Payment of dividends
- Equity purchases
- Asset sales
- Affiliate transactions

- Incurrence of debt
- Incurrence of liens
-Payment of dividends
- Equity purchases
- Asset sales
- Affiliate transactions

Optional redemption prior to acceleration ⁽⁹⁾

Any time

Any time, subject to re-pricing event
June 21, 2015: 101

August 15,
2014: 104.563
2015: 103.042
2016: 101.521
2017: par

July 1,
2019: 102.000
2020: par

Any time

Make-whole redemption prior to acceleration ⁽⁹⁾

N/A

Callable prior to
July 1, 2019 at
make-whole call price
of Treasury +50 bps

N/A

Change of control prior to acceleration ⁽⁹⁾

Event of default

Put at 101% of
principal plus accrued
interest

Equity clawback prior to acceleration ⁽⁹⁾

N/A

Redeemable until
July 1, 2016 at
111.00%, plus accrued
interest for up to 35%

N/A

Estimated fair value as of

September 30, 2015 ⁽¹⁰⁾

$157.0 million

$237.5 million

$76.0 million

$17.6 million

$20.9 million

$—

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⁽¹⁾

Borrowings under the Amended and Restated U.S. Credit Facility, Second Lien Term Loan and Second Lien Notes due 2019 are guaranteed by certain of Quicksilver’s domestic subsidiaries and are secured (on a first priority basis with respect to the Amended and Restated U.S. Credit Facility and on a second priority basis with respect to the Second Lien Term Loan and the Second Lien Notes due 2019) by 100% of the equity interests of each of Cowtown Pipeline Management, Inc., Cowtown Pipeline Funding, Inc., Cowtown Gas Processing L.P., Cowtown Pipeline L.P., Barnett Shale Operating LLC, Silver Stream Pipeline Company LLC, QPP Parent LLC and QPP Holdings LLC (collectively, the “Domestic Pledged Equity”), 65% of the equity interests of QRCI and Quicksilver Production Partners Operating Ltd. (with respect to the Amended and Restated U.S. Credit Facility, on a ratable basis with borrowings under the Amended and Restated Canadian Credit Facility) and the majority of Quicksilver's domestic proved oil and gas properties and related assets, (the “Domestic Pledged Property”). Borrowings under the Amended and Restated Canadian Credit Facility are guaranteed by Quicksilver and certain of its domestic subsidiaries and are secured by the Domestic Pledged Equity, the Domestic Pledged Property, 100% of the equity interests of QRCI (65% of which is on a ratable basis with the borrowings under the Amended and Restated U.S. Credit Facility) and any Canadian restricted subsidiaries, under the Amended and Restated Canadian Credit Facility, and 65% of the equity interests of Quicksilver Production Partners Operating Ltd. (which is on a ratable basis with the borrowings under the Amended and Restated U.S. Credit Facility) and the majority of QRCI's oil and gas properties and related assets. The other debt presented is based upon structural seniority and priority of payment.


⁽²⁾	The principal amount included in the table for the Combined Credit Agreements represents the global borrowing base immediately prior to the Chapter 11 filings.

⁽³⁾

Immediately prior to acceleration as a result of the Chapter 11 filings, the Combined Credit Agreements were required to be repaid 91 days prior to the maturity of the Senior Subordinated Notes, the Second Lien Term Loan or the Second Lien Notes due 2019, if on the applicable date any amount of such debt remained outstanding. Immediately prior to acceleration as a result of the Chapter 11 filings, the Second Lien Term Loan and Second Lien Notes due 2019 were required to be repaid (1) 91 days prior to the maturity of the 2019 Senior Notes if more than $100 million of the 2019 Senior Notes remained outstanding and (2) 91 days prior to the maturity of the Senior Subordinated Notes if on the applicable date the amount remaining outstanding was greater than $100 million. Immediately prior to acceleration as a result of the Chapter 11 filings, as then structured and assuming no changes in the amounts outstanding, amounts outstanding under the Combined Credit Agreements would have been due on October 2, 2015 and the Second Lien Term Loan and Second Lien Notes would have been due on January 1, 2016.


⁽⁴⁾	Represents the weighted average borrowing rate payable to lenders on our Combined Credit Agreement as of September 30, 2015.

⁽⁵⁾

Immediately prior to the Chapter 11 filings, amounts outstanding under the Amended and Restated U.S. Credit Facility bore interest, at our election, at (i) adjusted LIBOR (as defined in the Amended and Restated U.S. Credit Facility) plus an applicable margin between 2.75% and 3.75%, or (ii) ABR (as defined in the Amended and Restated U.S. Credit Facility), which is the greatest of (a) the prime rate announced by JPMorgan, (b) the federal funds rate plus 0.50% and (c) adjusted LIBOR for an interest period of one month plus 1.00%, plus, in each case under scenario (ii), an applicable margin between 1.75% and 2.75%. We also pay a per annum fee on the LC Exposure (as defined in the Amended and Restated U.S. Credit Facility) of all letters of credit issued under the Amended and Restated U.S. Credit Facility equal to the applicable margin with respect to Eurodollar loans, and a commitment fee on the unused availability under the Amended and Restated U.S. Credit Facility of 0.50%.

⁽⁶⁾

Immediately prior to the Chapter 11 filings, amounts outstanding under the Amended and Restated Canadian Credit Facility bore interest, at our election, at (i) the CDOR Rate (as defined in the Amended and Restated Canadian Credit Facility) plus an applicable margin between 2.75% and 3.75%, (ii) the Canadian Prime Rate (as defined in the Amended and Restated Canadian Credit Facility) plus an applicable margin between 1.75% and 2.75%, (iii) the U.S. Prime Rate (as defined in the Amended and Restated Canadian Credit Facility) plus an applicable margin between 1.75% and 2.75% or (iv) adjusted LIBOR (as defined in the Amended and Restated Canadian Credit Facility) plus an applicable margin between 2.75% and 3.75%. We also pay a per annum fee on the LC Exposure (as defined in the Amended and Restated Canadian Credit Facility) of all

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letters of credit issued under the Amended and Restated Canadian Credit Facility equal to the applicable margin with respect to Eurodollar loans, and a commitment fee on the unused availability under the Amended and Restated Canadian Credit Facility of 0.50%.

⁽⁷⁾

The financial covenants and significant restrictive covenants were applicable to the Combined Credit Agreements immediately prior to the Chapter 11 filings and remain applicable to the Amended and Restated Canadian Credit Facility. However, pursuant to the Forbearance Agreements, the administrative agent and certain lenders agreed to, among other things, forbear from exercising their rights and remedies in connection with specified defaults under the Amended and Restated Canadian Credit Facility, including events of default related to our Chapter 11 filings or the failure to comply with the financial covenants, until the earlier of December 15, 2015 or certain other events specified in the Forbearance Agreements.

The following table sets forth the minimum EBITDAX covenant for the Amended and Restated U.S. Credit Facility immediately prior to the Chapter 11 filings and for the Amended and Restated Canadian Credit Facility:



	Minimum EBITDAX Covenant
	(in millions)
Twelve months ending September 30, 2015	120.5
Twelve months ending December 31, 2015	122.0

Immediately prior to the Chapter 11 filings, the minimum required interest coverage ratio for the Amended and Restated U.S. Credit Facility for the first and second quarters of 2016 was 1.50 and 2.00, respectively. The minimum required interest coverage ratio for the Amended and Restated Canadian Credit Facility for the first and second quarters of 2016 is 1.50 and 2.00, respectively.


⁽⁸⁾	Immediately prior to acceleration as a result of our Chapter 11 filings, our indentures required us to reinvest or repay senior debt with net cash proceeds from certain asset sales within one year.


⁽⁹⁾	The information presented in this table is qualified in all respects by reference to the full text of the covenants, provisions and related definitions contained in the documents governing the various components of our debt.

⁽¹⁰⁾

The estimated fair value is determined using market quotations based on recent trade activity for fixed rate obligations (“Level 2” inputs). Our Second Lien Term Loan and Second Lien Notes feature variable interest rates and we estimate their fair value by using market quotations based on recent trade activity (“Level 3” input). We consider our Combined Credit Agreements, which have a variable interest rate, to have a fair value equal to their carrying value (“Level 1” input).

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Quicksilver Resources Inc. and its Restricted Subsidiaries

The following tables, required under our indentures, provide information about Quicksilver Resources Inc. and the entities designated as restricted subsidiaries under the indentures for our Second Lien Notes, Senior Notes and Senior Subordinated Notes. Eliminations between Quicksilver Resources Inc., the related restricted guarantor subsidiaries and restricted non-guarantor subsidiaries are included in the tables below as necessary.

Condensed Consolidating Balance Sheets



	September 30, 2015			December 31, 2014

	(in thousands)
	(Restated)
ASSETS
Current assets	$	216,433		$	421,533
Property and equipment	430,401			715,931
Investment in subsidiaries (equity method)	(87,936		)	(82,360		)
Other assets	6,640			62,245
Total assets	$	565,538		$	1,117,349
LIABILITIES AND EQUITY
Current liabilities	214,393			2,137,532
Long-term liabilities	108,639			117,688
Liabilities subject to compromise	1,884,128			—
Stockholders’ equity	(1,641,622		)	(1,137,871		)
Total liabilities and equity	$	565,538		$	1,117,349

Condensed Consolidating Statements of Income



	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2015			2014			2015			2014

	(in thousands)
	(Restated)						(Restated)
Revenue	$	58,987		$	163,498		$	227,119		$	373,316
Operating expenses	228,309			100,857			471,797			313,385
Equity in net earnings of subsidiaries	(1,004		)	(1,458		)	(2,991		)	(4,266		)
Operating income (loss)	(170,326		)	61,183			(247,669		)	55,665
Interest expense and other	(3,851		)	(42,365		)	(69,645		)	(125,755		)
Reorganization items, net	(7,883		)	—			(148,568		)	—
Income tax benefit (expense)	(2,152		)	4,939			(5,836		)	(1,081		)
Net income (loss)	$	(184,212	)	$	23,757		$	(471,718	)	$	(71,171	)
Other comprehensive loss	(5,659		)	(14,889		)	(23,549		)	(27,101		)
Comprehensive income (loss)	$	(189,871	)	$	8,868		$	(495,267	)	$	(98,272	)

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Condensed Consolidating Statements of Cash Flow



	For the Nine Months Ended September 30,
	2015			2014

	(in thousands)
Net cash flow provided by (used in) operating activities	$	113,640		$	(11,319	)
Capital expenditures	(25,007		)	(111,423		)
Investment in subsidiary	—			(26,395		)
Proceeds from Southwestern Transaction	—			95,587
Proceeds from sale of properties and equipment	2,978			1,942
Purchases of marketable securities	—			(55,890		)
Maturities and sales of marketable securities	—			222,025
Net cash flow provided by (used in) investing activities	(22,029		)	125,846
Issuance of debt	28,335			243,184
Repayments of debt	(170,660		)	(193,689		)
Debt issuance costs paid	(80		)	(225		)
Purchase of treasury stock	(115		)	(2,388		)
Net cash flow provided by (used in) financing activities	(142,520		)	46,882
Effect of exchange rates on cash	4,614			(2,718		)
Net change in cash and equivalents	(46,295		)	158,691
Cash and equivalents at beginning of period	221,838			88,028
Cash and equivalents at end of period	$	175,543		$	246,719

6. INCOME TAXES

Note 12 to the consolidated financial statements in our 2014 Annual Report on Form 10-K contains additional information about our income taxes. At September 30, 2015, our U.S. and Canadian valuation allowances are $455.3 million and $96.1 million, respectively, which reduce our net deferred tax assets to a zero value as we continue to believe that it is not more likely than not that we will realize the deferred tax assets primarily related to our cumulative net operating losses. Income tax recognized for the nine months ended September 30, 2015 is a result of hedge gains previously deferred in AOCI being realized during the periods.

In June 2015, the Alberta government passed regulation to increase the provincial tax rate by 2% with an effective date of July 2015. We have adjusted our rates based on this change.

7. COMMITMENTS AND CONTINGENCIES

QRCI did not pay an uneconomic Canadian gathering and processing commitment, which included significant unused firm capacity, due in late February 2015. In early March 2015, the third-party service provider issued a demand letter regarding the missed payment and suspended service resulting in our Horn River Asset production being shut-in. Further, a termination notice was issued by the third-party service provider effective March 19, 2015. We continue to explore alternatives to gather and process our Horn River Asset production; however, we may not be able to find economic alternatives in the near-term, or at all, and production may remain shut-in.

In connection with this Canadian gathering and processing contract, we had previously issued a letter of credit in the amount of C$33 million. Upon termination, the third party drew down the full face amount of the letter of credit. We do not believe the third party was legally entitled to draw down the entire amount of the letter of credit and we have reserved all of our rights, entitlements and remedies in that regard. The $26.2 million (C$33 million) draw is shown as a reduction to amounts outstanding under the contract for services provided prior to the termination and the remaining $21.5 million is recognized as Other Expense. At the present time, we cannot predict the ultimate outcome of this matter, including whether some or all of the C$33 million drawn on the letter

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of credit will be payable to us or whether any additional amounts will have to be paid related to the termination of the contract.

We expect that we and the third party will disagree as to what are the remaining obligations under the relevant agreement and the length of the remaining term of the agreement and as to the remedies and defenses available to the parties. While we expect to vigorously dispute the amount, we expect that the third party will claim to be entitled to up to approximately C$126 million (including the proceeds of the letter of credit) as the aggregate of the monthly tolls for firm capacity for the alleged remainder of the term of the relevant agreement.

Note 1 to this Quarterly Report contains a description of our claims reconciliation process associated with the bankruptcy proceedings.

On April 15 and May 8, 2015, the Bankruptcy Court issued orders allowing us to reject certain executory contracts effective March 17 and April 1, 2015 and the total estimated allowable claim under these contracts has been included in Liabilities Subject to Compromise and Reorganization Items, net as appropriate. The reductions impacted our GPT contracts included in the contractual obligation table included in our 2014 Form 10-K and reduced our total payments due over the life of the contracts as of the date the contracts were rejected by approximately $39 million.

We renegotiated an NGL GPT contract in our Barnett Shale Asset effective April 2015, which reduced our GPT contracts included in the contractual obligation table included in our 2014 Form 10-K over the life of the contract by approximately $100 million.

Note 13 to the consolidated financial statements in our 2014 Annual Report on Form 10-K contains a more complete description of our contractual obligations, commitments and contingencies for which there are no other significant updates during the quarter ended September 30, 2015.

8. FORTUNE CREEK

Note 14 to the consolidated financial statements in our 2014 Annual Report on Form 10-K contains additional information on Fortune Creek. We do not expect to be able to satisfy the capital expenditure or equipment purchase requirements described in our 2014 Annual Report on Form 10-K with our cash on hand, committed financing or cash flow from operations and will need to obtain additional debt or equity financing or sell assets, which we may not be able to do on satisfactory terms, or at all.

We committed gas production from our Horn River Asset for ten years beginning 2012. KKR contributed C$125 million cash in exchange for a 50% interest in Fortune Creek. Our Canadian subsidiary has responsibility for the day-to-day operations of Fortune Creek.

The firm gathering agreement with Fortune Creek is guaranteed by us. If our subsidiary does not pay its minimum volume obligations under the gathering agreement or meet the capital expenditure requirements, KKR has the right to liquidate the partnership and consequently we have recorded the funds contributed by KKR as a liability in our consolidated financial statements. We recognize accretion expense to reflect the rate of return earned by KKR via its investment. Fortune Creek has made cash distributions to KKR, which are reported as cash used in financing activities.

QRCI did not make an approximately C$1.6 million payment due at the end of June 2015 and has not made subsequent monthly payments of the same amount pursuant to the gathering agreement with Fortune Creek. As a result, among other things: (i) Fortune Creek may discontinue transporting QRCI's gas until all amounts owing are repaid (although, as previously disclosed, production was previously shut-in due to the termination of a third-party gathering and processing agreement in March 2015); (ii) if the non-payment continues for more than 90 days after a written demand therefor, subject to certain existing contracts for the sale of gas, Fortune Creek may enforce the lien granted by QRCI to Fortune Creek on the natural gas belonging to QRCI while it is in the Maxhamish Pipeline and in Fortune Creek's possession; (iii) Fortune Creek has certain set-off rights against QRCI; (iv) if the non-payment continues for 180 days (or 60 days following a written notice by the other partner), we will not be entitled to receive partnership distributions or vote with respect to partnership matters until the non-payment is cured and Fortune Creek may be dissolved or our partnership interest in Fortune Creek may be purchased by the other partner; and (v) the operating agreement could be terminated by Fortune Creek. We have not received any written notices regarding the past due amounts. Past due amounts under the gathering agreement bear interest compounded monthly at prime plus 2%. We are in discussions with KKR in connection with the issues related to Fortune Creek; however, we may not reach a resolution in the near-term, or at all.

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Based on a quarterly analysis of the partners’ equity at risk, we have determined the partnership to be a VIE. Further, based on our ability to direct the activities surrounding the production of natural gas and our direct management of the operations of the Fortune Creek facilities, we have determined we are the primary beneficiary and, therefore, we consolidate Fortune Creek. We will continue to evaluate this assessment in light of our bankruptcy filings in the U.S., breach of contract due to non-payment and our liquidity constraints in Canada; however, if we are unable to resolve these items, we may no longer be the primary beneficiary and may therefore not consolidate Fortune Creek as early as the fourth quarter of 2015.

9. QUICKSILVER STOCKHOLDERS’ EQUITY

Common Stock, Preferred Stock and Treasury Stock

We are authorized to issue 400 million shares of common stock with a $0.01 par value per share and 10 million shares of preferred stock with a $0.01 par value per share. At September 30, 2015 and December 31, 2014, we had 183.1 million and 180.4 million shares of common stock outstanding, respectively.

Stock Options

No options have been granted during 2015 or were granted during 2014.

The following table summarizes our stock option activity for the nine months ended September 30, 2015:



	Shares		Weighted Average Exercise Price		Weighted Average Remaining Contractual Life	Aggregate Intrinsic Value
					(in years)	(in thousands)
Outstanding at January 1, 2015	6,590,773		$	7.83
Expired	(201,586	)	10.92
Outstanding at September 30, 2015	6,389,187		$	7.73	4.5	$	—
Exercisable at September 30, 2015	5,284,867		$	9.00	3.8	$	—

As of September 30, 2015, we estimate that a total of 6.1 million stock options will vest, including those options already exercisable. As of September 30, 2015, the unrecognized compensation cost related to outstanding unvested stock options was $0.3 million, which is expected to be recognized in expense through August 2016. Compensation expense related to stock options of $0.2 million and $1.1 million was recognized for the nine months ended September 30, 2015 and 2014, respectively.

Restricted Stock and Stock Units

The following table summarizes our restricted stock and stock unit activity for the nine months ended September 30, 2015:



	Payable in shares				Payable in cash
	Shares		Weighted Average Grant Date Fair Value		Shares		Weighted Average Grant Date Fair Value
Outstanding at January 1, 2015	8,056,265		$	2.54	863,975		$	3.33
Granted	3,124,674		0.19		—		—
Vested	(3,205,592	)	3.16		(523,432	)	3.57
Forfeited	(162,343	)	2.41		(5,233	)	2.93
Outstanding at September 30, 2015	7,813,004		$	1.35	335,310		$	2.96

As of September 30, 2015, the unrecognized compensation cost related to outstanding unvested restricted stock was $6.1 million, which is expected to be recognized in expense through January 2018. Grants of restricted stock and RSUs during the nine months ended September 30, 2015 had an estimated grant date fair value of $0.6 million. The fair value of outstanding RSUs to be settled in cash was less than $0.1 million at September 30, 2015.

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For the nine months ended September 30, 2015 and 2014, compensation expense related to restricted stock and RSUs of $4.9 million and $8.4 million, respectively, was recognized. The total fair value of shares vested during the nine months ended September 30, 2015 was $0.5 million.

10. EARNINGS PER SHARE

The following is a reconciliation of the numerator and denominator used for the computation of basic and diluted net income (loss) per common share.



	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2015			2014			2015			2014

	(in thousands, except per share data)
	(Restated)						(Restated)
Net income (loss) attributable to Quicksilver	$	(184,212	)	$	23,757		$	(471,718	)	$	(71,171	)
Basic income allocable to participating securities ⁽¹⁾	—			(772		)	—			—
Income (loss) available to shareholders	$	(184,212	)	$	22,985		$	(471,718	)	$	(71,171	)
Weighted average common shares – basic	176,206			173,936			176,021			173,783
Effect of dilutive securities ⁽²⁾
Share-based compensation awards	—			216			—			—
Weighted average common shares – diluted	176,206			174,152			176,021			173,783
Earnings (loss) per common share – basic	$	(1.05	)	$	0.13		$	(2.68	)	$	(0.41	)
Earnings (loss) per common share – diluted	$	(1.05	)	$	0.13		$	(2.68	)	$	(0.41	)


⁽¹⁾	Restricted share awards that contain nonforfeitable rights to dividends are participating securities and, therefore, are included in computing earnings per share using the two-class method. Participating securities, however, do not participate in undistributed net losses because there is no contractual obligation to do so.

⁽²⁾

For the three months ended September 30, 2015, 6.4 million shares associated with our stock options and 0.9 million shares associated with our unvested RSUs were antidilutive and, therefore, excluded from the diluted share calculations. For the three months ended September 30, 2014, 6.6 million shares associated with our stock options and 1.2 million shares associated with our unvested RSUs were antidilutive and, therefore, excluded from the diluted share calculations. For the nine months ended September 30, 2015, 6.4 million shares associated with our stock options and 0.9 million shares associated with our unvested RSUs were antidilutive and, therefore, excluded from the diluted share calculations. For the nine months ended September 30, 2014, 6.6 million shares associated with our stock options and 0.8 million shares associated with our unvested RSUs were antidilutive and, therefore, excluded from the diluted share calculations.

11. CONDENSED CONSOLIDATING FINANCIAL INFORMATION

Note 17 to the consolidated financial statements in our 2014 Annual Report on Form 10-K contains a more complete description of our guarantor, non-guarantor, restricted and unrestricted subsidiaries under the indentures for our Second Lien Notes, Senior Notes and Senior Subordinated Notes.

The following tables present financial information about Quicksilver and our restricted subsidiaries for the three- and nine-month periods covered by the condensed consolidated financial statements. Under the indentures for our Second Lien Notes, Senior Notes and Senior Subordinated Notes, Fortune Creek is not considered to be a subsidiary and therefore it is presented separately from the other subsidiaries for these purposes.

The activity and balances included in the Quicksilver Resources Inc. and the Restricted Guarantor Subsidiaries columns represent the U.S. Debtors’ financial information. Cowtown Drilling Inc., a U.S. Debtor, is included in the Restricted Non-Guarantor Subsidiaries column, however, no activity occurred and no balances exist for the periods presented below. Additionally, Makarios Resources International Holdings LLC, Makarios Resources International Inc., Quicksilver Production Partners GP LLC and Quicksilver Production Partners LP, all

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of which are U.S. Debtors, are included in the Unrestricted Non-Guarantor Subsidiaries column, however, no activity occurred and no balances exist for the periods presented below.

The U.S. Debtors had a net receivable balance of $4.8 million at September 30, 2015, and a net payable balance of $1.6 million at December 31, 2014, to non-debtors. The receivable balance at September 30, 2015 was primarily due to the non-debtors not making interest payments of approximately $0.7 million per month beginning with the interest payment due in March 2015 on a $413.3 million intercompany loan, which principal amount has been unchanged since December 31, 2014.

Condensed Consolidating Balance Sheets



	September 30, 2015 (Restated)
	Debtors					Non-Debtors
	Quicksilver Resources Inc.			Restricted Guarantor Subsidiaries		Restricted Non- Guarantor Subsidiaries			Unrestricted Non- Guarantor Subsidiaries			Fortune Creek		Consolidated Eliminations			Quicksilver Resources Inc. Consolidated
	(in thousands)
ASSETS
Current assets	$	190,165		$	1,981	$	24,287		$	17		$	4,554	$	—		$	221,004
Property and equipment	269,896			13,545		146,960			—			10,419		—			440,820
Investment in subsidiaries (equity method)	(467,867		)	—		(87,936		)	(86,499		)	—		642,302			—
Other assets	415,257			—		4,665			—			—		(413,282		)	6,640
Total assets	$	407,451		$	15,526	$	87,976		$	(86,482	)	$	14,973	$	229,020		$	668,464

LIABILITIES AND EQUITY
Current liabilities	$	130,132		$	401	$	497,142		$	—		$	124	$	(413,282	)	$	214,517
Long-term liabilities	46,237			10,195		52,207			—			1,347		87,935			197,921
Liabilities subject to compromise	1,884,128			—		—			—			—		—			1,884,128
Stockholders' equity	(1,653,046		)	4,930		(461,373		)	(86,482		)	13,502		554,367			(1,628,102		)
Total liabilities and equity	$	407,451		$	15,526	$	87,976		$	(86,482	)	$	14,973	$	229,020		$	668,464



	December 31, 2014
	Debtors						Non-Debtors
	Quicksilver Resources Inc.			Restricted Guarantor Subsidiaries			Restricted Non- Guarantor Subsidiaries			Unrestricted Non- Guarantor Subsidiaries			Fortune Creek		Consolidated Eliminations			Quicksilver Resources Inc. Consolidated
	(in thousands)
ASSETS
Current assets	$	774,287		$	13,909		$	68,513		$	82		$	1,742	$	(435,256	)	$	423,277
Property and equipment	420,744			14,357			280,830			—			12,849		—			728,780
Investment in subsidiaries (equity method)	(293,312		)	—			(82,360		)	(82,379		)	—		458,051			—
Other assets	43,533			—			18,712			—			—		—			62,245
Total assets	$	945,252		$	28,266		$	285,695		$	(82,297	)	$	14,591	$	22,795		$	1,214,302

LIABILITIES AND EQUITY
Current liabilities	$	2,038,575		$	13,837		$	520,296		$	63		$	3,522	$	(435,256	)	$	2,141,037
Long-term liabilities	44,548			15,131			58,009			—			1,492		91,956			211,136
Stockholders' equity	(1,137,871		)	(702		)	(292,610		)	(82,360		)	9,577		366,095			(1,137,871		)
Total liabilities and equity	$	945,252		$	28,266		$	285,695		$	(82,297	)	$	14,591	$	22,795		$	1,214,302

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Condensed Consolidating Statements of Income



	For the Three Months Ended September 30, 2015 (Restated)
	Debtors					Non-Debtors
	Quicksilver Resources Inc.			Restricted Guarantor Subsidiaries		Restricted Non- Guarantor Subsidiaries			Unrestricted Non- Guarantor Subsidiaries		Fortune Creek		Consolidated Eliminations			Quicksilver Resources Inc. Consolidated
	(in thousands)
Revenue	$	46,964		$	941	$	11,515		$	—	$	2,974	$	(3,407	)	$	58,987
Operating expenses	197,553			613		30,576			—		699		(3,407		)	226,034
Equity in net earnings of subsidiaries	(23,981		)	—		(1,004		)	2,275		—		22,710			—
Operating income (loss)	(174,570		)	328		(20,065		)	2,275		2,275		22,710			(167,047		)
Fortune Creek accretion	—			—		—			—		—		(3,279		)	(3,279		)
Interest expense and other	571			—		(4,422		)	—		—		—			(3,851		)
Reorganization items, net	(7,883		)	—		—			—		—		—			(7,883		)
Income tax (expense) benefit	(2,330		)	—		178			—		—		—			(2,152		)
Net income (loss)	$	(184,212	)	$	328	$	(24,309	)	$	2,275	$	2,275	$	19,431		$	(184,212	)
Other comprehensive loss	(4,228		)	—		(1,431		)	—		—		—			(5,659		)
Equity in OCI of subsidiaries	(1,431		)	—		—			—		—		1,431			—
Comprehensive income (loss)	$	(189,871	)	$	328	$	(25,740	)	$	2,275	$	2,275	$	20,862		$	(189,871	)



	For the Three Months Ended September 30, 2014
	Debtors						Non-Debtors
	Quicksilver Resources Inc.			Restricted Guarantor Subsidiaries			Restricted Non- Guarantor Subsidiaries			Unrestricted Non- Guarantor Subsidiaries		Fortune Creek		Consolidated Eliminations			Quicksilver Resources Inc. Consolidated
	(in thousands)
Revenue	$	120,513		$	427		$	42,558		$	—	$	4,271	$	(4,271	)	$	163,498
Operating expenses	72,868			341			27,648			—		2,128		(4,271		)	98,714
Equity in net earnings of subsidiaries	8,821			—			(1,458		)	2,144		—		(9,507		)	—
Operating income (loss)	56,466			86			13,452			2,144		2,143		(9,507		)	64,784
Fortune Creek accretion	—			—			—			—		—		(3,602		)	(3,602		)
Interest expense and other	(37,613		)	86			(4,838		)	—		1		—			(42,364		)
Income tax (expense) benefit	4,826			(30		)	65			—		—		78			4,939
Net income (loss)	$	23,679		$	142		$	8,679		$	2,144	$	2,144	$	(13,031	)	$	23,757
Other comprehensive loss	(11,564		)	—			(3,325		)	—		—		—			(14,889		)
Equity in OCI of subsidiaries	(3,325		)	—			—			—		—		3,325			—
Comprehensive income (loss)	$	8,790		$	142		$	5,354		$	2,144	$	2,144	$	(9,706	)	$	8,868

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	For the Nine Months Ended September 30, 2015 (Restated)
	Debtors					Non-Debtors
	Quicksilver Resources Inc.			Restricted Guarantor Subsidiaries		Restricted Non- Guarantor Subsidiaries			Unrestricted Non- Guarantor Subsidiaries		Fortune Creek		Consolidated Eliminations			Quicksilver Resources Inc. Consolidated
	(in thousands)
Revenue	$	173,027		$	7,402	$	47,937		$	—	$	8,831	$	(10,078	)	$	227,119
Operating expenses	319,363			1,769		151,912			—		1,947		(10,078		)	464,913
Equity in net earnings of subsidiaries	(138,506		)	—		(2,991		)	6,886		—		134,611			—
Operating income (loss)	(284,842		)	5,633		(106,966		)	6,886		6,884		134,611			(237,794		)
Fortune Creek accretion	—			—		—			—		—		(9,877		)	(9,877		)
Interest expense and other	(31,815		)	—		(37,830		)	—		2		—			(69,643		)
Reorganization items, net	(148,568		)	—		—			—		—		—			(148,568		)
Income tax (expense) benefit	(6,493		)	—		657			—		—		—			(5,836		)
Net income (loss)	$	(471,718	)	$	5,633	$	(144,139	)	$	6,886	$	6,886	$	124,734		$	(471,718	)
Other comprehensive loss	(18,444		)	—		(5,105		)	—		—		—			(23,549		)
Equity in OCI of subsidiaries	(5,105		)	—		—			—		—		5,105			—
Comprehensive income (loss)	$	(495,267	)	$	5,633	$	(149,244	)	$	6,886	$	6,886	$	129,839		$	(495,267	)



	For the Nine Months Ended September 30, 2014
	Debtors						Non-Debtors
	Quicksilver Resources Inc.			Restricted Guarantor Subsidiaries			Restricted Non- Guarantor Subsidiaries			Unrestricted Non- Guarantor Subsidiaries		Fortune Creek		Consolidated Eliminations			Quicksilver Resources Inc. Consolidated
	(in thousands)
Revenue	$	269,321		$	1,212		$	102,783		$	—	$	13,349	$	(13,349	)	$	373,316
Operating expenses	225,906			988			86,491			—		6,014		(13,349		)	306,050
Equity in net earnings of subsidiaries	2,864			—			(4,266		)	7,339		—		(5,937		)	—
Operating income (loss)	46,279			224			12,026			7,339		7,335		(5,937		)	67,266
Fortune Creek accretion	—			—			—			—		—		(11,605		)	(11,605		)
Interest expense and other	(117,315		)	86			(8,526		)	—		4		—			(125,751		)
Income tax (expense) benefit	(213		)	(78		)	(868		)	—		—		78			(1,081		)
Net income (loss)	$	(71,249	)	$	232		$	2,632		$	7,339	$	7,339	$	(17,464	)	$	(71,171	)
Other comprehensive loss	(20,252		)	—			(6,849		)	—		—		—			(27,101		)
Equity in OCI of subsidiaries	(6,849		)	—			—			—		—		6,849			—
Comprehensive income (loss)	$	(98,350	)	$	232		$	(4,217	)	$	7,339	$	7,339	$	(10,615	)	$	(98,272	)

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Condensed Consolidating Statements of Cash Flows



	For the Nine Months Ended September 30, 2015
	Debtors						Non-Debtors
	Quicksilver Resources Inc.			Restricted Guarantor Subsidiaries			Restricted Non-Guarantor Subsidiaries			Unrestricted Non-Guarantor Subsidiaries			Fortune Creek			Consolidated Eliminations			Quicksilver Resources Inc. Consolidated
	(in thousands)
Net cash flow provided by (used in) operating activities	$	97,516		$	(444	)	$	16,568		$	(3	)	$	(1,768	)	$	—		$	111,869
Purchases of property, plant and equipment	(21,576		)	—			(3,431		)	—			—			—			(25,007		)
Investment in subsidiary	(6,920		)	—			—			—			—			6,920			—
Proceeds from sale of properties and equipment	1,504			—			1,474			—			—			—			2,978
Net cash flow provided by (used in) investing activities	(26,992		)	—			(1,957		)	—			—			6,920			(22,029		)
Issuance of debt	2,100			—			26,235			—			—			—			28,335
Repayments of debt	(129,084		)	—			(41,576		)	—			—			—			(170,660		)
Debt issuance costs paid	(80		)	—			—			—			—			—			(80		)
Intercompany financing	—			444			6,476			—			—			(6,920		)	—
Distribution of Fortune Creek Partnership funds	—			—			—			—			(1,426		)	—			(1,426		)
Purchase of treasury stock	(115		)	—			—			—			—			—			(115		)
Net cash flow provided by (used in) financing activities	(127,179		)	444			(8,865		)	—			(1,426		)	(6,920		)	(143,946		)
Effect of exchange rates on cash	—			—			4,614			—			1,636			—			6,250
Net increase (decrease) in cash and equivalents	(56,655		)	—			10,360			(3		)	(1,558		)	—			(47,856		)
Cash and equivalents at beginning of period	211,656			—			10,182			20			1,671			—			223,529
Cash and equivalents at end of period	$	155,001		$	—		$	20,542		$	17		$	113		$	—		$	175,673

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	For the Nine Months Ended September 30, 2014
	Debtors						Non-Debtors
	Quicksilver Resources Inc.			Restricted Guarantor Subsidiaries			Restricted Non-Guarantor Subsidiaries			Unrestricted Non-Guarantor Subsidiaries			Fortune Creek			Consolidated Eliminations			Quicksilver Resources Inc. Consolidated
	(in thousands)
Net cash flow provided by (used in) operating activities	$	(39,474	)	$	(688	)	$	28,843		$	—		$	6,336		$	—		$	(4,983	)
Purchases of property, plant and equipment	(88,119		)	(57		)	(23,247		)	—			(21		)	—			(111,444		)
Investment in subsidiary	(1,246		)	—			(26,395		)	(26,395		)	—			54,036			—
Proceeds from Southwestern Transaction	95,587			—			—			—			—			—			95,587
Proceeds from sale of properties and equipment	1,445			—			497			—			—			—			1,942
Purchases of marketable securities	(55,890		)	—			—			—			—			—			(55,890		)
Maturities and sales of marketable securities	222,025			—			—			—			—			—			222,025
Net cash flow provided by (used in) investing activities	173,802			(57		)	(49,145		)	(26,395		)	(21		)	54,036			152,220
Issuance of debt	174,000			—			69,184			—			—			—			243,184
Repayments of debt	(138,651		)	—			(55,038		)	—			—			—			(193,689		)
Debt issuance costs paid	(225		)	—			—			—			—			—			(225		)
Intercompany note	(22,558		)	—			22,558			—			—			—			—
Intercompany financing	—			745			501			—			—			(1,246		)	—
Contribution received	—			—			—			26,395			26,395			(52,790		)	—
Distribution of Fortune Creek Partnership funds	—			—			—			—			(37,113		)	—			(37,113		)
Purchase of treasury stock	(2,388		)	—			—			—			—			—			(2,388		)
Net cash flow provided by (used in) financing activities	10,178			745			37,205			26,395			(10,718		)	(54,036		)	9,769
Effect of exchange rates on cash	—			—			(2,718		)	—			4,934			—			2,216
Net increase (decrease) in cash and equivalents	144,506			—			14,185			—			531			—			159,222
Cash and equivalents at beginning of period	83,893			—			4,135			22			1,053			—			89,103
Cash and equivalents at end of period	$	228,399		$	—		$	18,320		$	22		$	1,584		$	—		$	248,325

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12. SEGMENT INFORMATION

We operate in two geographic areas, the U.S. and Canada, where we are engaged in the exploration and production segment of the oil and gas industry. Additionally, we operate a significantly smaller midstream segment in the U.S. and Canada, where we provide natural gas gathering and processing services, primarily to our U.S. and Canadian exploration and production segments. In Canada, our midstream operation is the Fortune Creek partnership. Revenue earned by Fortune Creek for the gathering and processing of our gas is eliminated on a consolidated basis as is the GPT recognized by our producing properties. Based on the immateriality of our midstream segment, we have combined our U.S. and Canadian midstream information. We evaluate performance based on operating income and property and equipment costs incurred.



	Exploration & Production														Quicksilver Consolidated
	U.S.			Canada			Midstream		Corporate			Elimination			Quicksilver Consolidated

For the Three Months Ended September 30:	(in thousands)
2015 (Restated)
Revenue	$	46,964		$	11,076		$	3,921	$	—		$	(2,974	)	$	58,987
DD&A	6,133			4,615			543		359			—			11,650
Impairment expense	150,816			13,702			—		—			—			164,518
Operating income (loss)	(140,889		)	(18,180		)	2,602		(10,580		)	—			(167,047		)
Property and equipment costs incurred	3,664			993			—		55			—			4,712
2014
Revenue	$	120,513		$	42,072		$	5,184	$	—		$	(4,271	)	$	163,498
DD&A	8,096			4,171			1,256		446			—			13,969
Impairment expense	—			—			135		—			—			135
Operating income (loss)	57,809			16,364			2,367		(11,756		)	—			64,784
Property and equipment costs incurred	20,912			7,254			72		218			—			28,456
For the Nine Months Ended September 30:	(in thousands)
2015 (Restated)
Revenue	$	173,028		$	46,631		$	16,291	$	—		$	(8,831	)	$	227,119
DD&A	19,452			17,495			1,660		1,186			—			39,793
Impairment expense	150,816			91,113			—		—			—			241,929
Operating income (loss)	(109,089		)	(100,723		)	12,516		(40,498		)	—			(237,794		)
Property and equipment costs incurred	19,615			2,557			48		325			—			22,545
2014
Revenue	$	269,310		$	101,198		$	16,157	$	—		$	(13,349	)	$	373,316
DD&A	23,652			13,779			3,744		1,409			—			42,584
Impairment expense	—			—			135		—			—			135
Operating income (loss)	78,891			20,199			7,700		(39,524		)	—			67,266
Property and equipment costs incurred	85,814			20,924			83		763			—			107,584
Property, plant and equipment-net
September 30, 2015 (Restated)	$	266,992		$	146,960		$	23,964	$	2,904		$	—		$	440,820
December 31, 2014	416,901			280,830			27,205		3,844			—			728,780
Total assets
September 30, 2015 (Restated)	$	547,085		$	87,976		$	30,499	$	2,904		$	—		$	668,464
December 31, 2014	881,906			285,695			42,857		3,844			—			1,214,302

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13. SUPPLEMENTAL CASH FLOW INFORMATION

Cash paid (received) for interest, income taxes and reorganization items is as follows:



	For the Nine Months Ended September 30,
	2015		2014

	(in thousands)
Interest, net of capitalized interest	$	25,613	$	124,408
Income taxes	146		(7,844		)
Reorganization items	14,885		—

Other significant non-cash transactions are as follows:



	For the Nine Months Ended September 30,
	2015		2014

	(in thousands)
Working capital related to capital expenditures	$	989	$	7,612

14. TRANSACTIONS AND OTHER MATTERS WITH RELATED PARTIES

As of September 30, 2015, members of the Darden family and entities controlled by them beneficially owned approximately 25% of our outstanding common stock. Glenn Darden and Anne Darden Self are officers and directors of Quicksilver.

Payments received from Mercury, a company owned by members of the Darden family, for sublease rentals and administrative services were less than $0.1 million for the first nine months of 2015 and 2014.

In May 2013, we entered into an agreement with Thomas F. Darden, brother of Glenn Darden and Anne Darden Self, with respect to Mr. Darden’s retirement and Mr. Darden’s provision of consulting services following his retirement. Mr. Darden retired as an employee on December 31, 2013, and resigned from the board of directors effective September 1, 2014. During the first nine months of 2015, consulting fee payments of $45,000 and office allowance payments of $12,500 were made to Mr. Darden. During the first nine months of 2014, consulting fee payments of $405,000, office allowance payments of $112,500 and COBRA payments of $39,000 were made to Mr. Darden. Additionally, in accordance with the agreement, and following the execution and non-revocation of a release agreement satisfactory to us, in March 2014, we paid Mr. Darden a cash bonus of $286,650 and an equity bonus in the form of 72,662 fully vested shares having a grant date fair value equal to $191,100. We did not make consulting fee payments of $90,000 or office allowance payments of $25,000 for February or March 2015 and, on April 15, 2015, the Bankruptcy Court entered an order authorizing our rejection of the agreement effective as of March 17, 2015. The remaining amount owed under the agreement was $1.3 million. These amounts are included in Liabilities Subject to Compromise on the balance sheet as of September 30, 2015.

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ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following Management’s Discussion and Analysis (“MD&A”) is intended to help readers of our financial statements understand our business, results of operations, financial condition, liquidity and capital resources. MD&A is provided as a supplement to, and should be read in conjunction with, the other sections of this Quarterly Report as well as our 2014 Annual Report on Form 10-K. We conduct our operations in two segments: (1) our more dominant exploration and production segment and (2) our significantly smaller midstream segment. Except as otherwise specifically noted, or as the context requires otherwise, and except to the extent that differences between these segments or our geographic segments are material to an understanding of our business taken as a whole, we present this MD&A on a consolidated basis.

Our MD&A includes the following sections:


•	Chapter 11 Filings – a description of recent events and our Chapter 11 filings


•	2015 Capital Program – a summary of our planned capital expenditures during 2015


•	Results of Operations – an analysis of our consolidated results of operations for the three- and nine-month periods presented in our financial statements


•	Liquidity, Capital Resources and Financial Position – an analysis of our cash flows, sources and uses of cash, contractual obligations and commercial commitments

CHAPTER 11 FILINGS

During the third quarter of 2014, we launched a formal marketing process, led by Houlihan Lokey, covering any and all of our operating assets. During the formal marketing process, we also received additional amendments to the financial covenants to our Combined Credit Agreements. These amendments, which included the replacement of the minimum interest coverage ratio with a minimum EBITDAX requirement, provided relief from the continued pressure on our cash flows relative to our obligations, which in turn allowed time for the formal marketing process. Bids were initially due in December 2014, but the bid deadline was subsequently extended to late January 2015. After the bid deadline passed, we evaluated the bids that were received with our advisors. Following discussions with various bidders, we concluded that the marketing process had not yet produced any viable options for asset sales or other strategic alternatives that would likely have a material impact on our capital structure or liquidity.

In February 2015, in light of (a) not yet having identified a transaction that would have a material impact on our capital structure or liquidity, (b) the potential springing maturities under our Combined Credit Agreements, the Second Lien Term Loan and the Second Lien Notes, and (c) other potential defaults, we elected not to make the approximately $13.6 million interest payment on our Senior Notes due 2019, which was due on February 17, 2015. During the 30-day grace period provided for in the Senior Notes due 2019 Indenture, we continued discussions with our creditors. The discussions with our creditors did not produce an agreement that would enable us to effectively address, in a holistic manner, the impending issues adversely impacting our business, including (i) potential springing maturities under our Combined Credit Agreements, the Second Lien Term Loan and the Second Lien Notes, (ii) potential near-term liquidity shortfalls due to the springing maturities, (iii) potential near-term breaches of certain financial covenants resulting from sharp declines in natural gas and NGL prices, and (iv) certain other potential defaults under our Combined Credit Agreements and the Second Lien Term Loan.

Accordingly, on March 17, 2015, the Company and our subsidiaries Barnett Shale Operating LLC, Cowtown Drilling, Inc., Cowtown Gas Processing L.P., Cowtown Pipeline Funding, Inc., Cowtown Pipeline L.P., Cowtown Pipeline Management, Inc., Makarios Resources International Holdings LLC, Makarios Resources International Inc., QPP Holdings LLC, QPP Parent LLC, Quicksilver Production Partners GP LLC, Quicksilver Production Partners LP, and Silver Stream Pipeline Company LLC each filed a voluntary petition under Chapter 11 in the Bankruptcy Court to restructure our obligations and capital structure. The Chapter 11 cases are being jointly administered for procedural purposes only by the Bankruptcy Court under the caption In re Quicksilver Resources Inc., et. al., Case No. 15-10585 (LSS) (Jointly Administered).

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lienholders and critical vendors, and forward funds belonging to third parties, including royalty holders and partners, as well as the approval of the U.S. Debtors’ use of their secured lenders’ cash collateral and collateral, and the provision of adequate protection related thereto. The order authorizing the U.S. Debtors to use collateral and cash collateral will expire on December 17, 2015. The U.S. Debtors will be seeking and expect to receive authority to use collateral and cash collateral beyond December 17, 2015. While the U.S. Debtors are subject to Chapter 11, all transactions outside the ordinary course of their business will require the prior approval of the Bankruptcy Court.

For the duration of our Chapter 11 proceedings, our operations and our ability to develop and execute our business plan are subject to the risks and uncertainties associated with the Chapter 11 process as described in our 2014 Annual Report on Form 10-K Item 1A, “Risk Factors.” As a result of these risks and uncertainties, the number of our outstanding shares and our shareholders, assets, liabilities, officers and/or directors could be significantly different following the outcome of the Chapter 11 proceedings, and the description of our operations, properties and capital plans included in this Quarterly Report may not accurately reflect our operations, properties and capital plans following the Chapter 11 process.

In particular, subject to certain exceptions, under the Bankruptcy Code, the U.S. Debtors may assume, assign, or reject certain executory contracts and unexpired leases subject to the approval of the Bankruptcy Court and certain other conditions. The rejection of an executory contract or unexpired lease is generally treated as a pre-petition breach of such executory contract or unexpired lease and, subject to certain exceptions, relieves the U.S. Debtors of performing their future obligations under such executory contract or unexpired lease but entitles the contract counterparty or lessor to a pre-petition general unsecured claim for damages caused by such deemed breach. Counterparties to such rejected contracts or leases may assert claims against the applicable U.S. Debtor's estate for such damages. The assumption of an executory contract or unexpired lease generally requires the U.S. Debtors to cure existing monetary defaults under such executory contract or unexpired lease and provide adequate assurance of future performance. Accordingly, any description of an executory contract or unexpired lease with the U.S. Debtors in this Quarterly Report, including where applicable a quantification of our obligations under any such executory contract or unexpired lease with the U.S. Debtors, is qualified by any overriding rejection rights we have under the Bankruptcy Code. Further, nothing herein is or shall be deemed an admission with respect to any claim amounts or calculations arising from the rejection of any executory contract or unexpired lease and the U.S. Debtors expressly preserve all of their rights with respect thereto.

As of October 27, 2015, approximately 498 claims totaling about $14.6 billion have been filed with the Bankruptcy Court against the U.S. Debtors, and we expect amended claims to be filed in the future, including

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claims amended to assign values to claims originally filed with no designated value. Through the claims resolution process, we have identified, and we expect to continue to identify, claims that we believe should be disallowed by the Bankruptcy Court because they are duplicative, have been later amended or superseded, are without merit, are overstated or for other reasons. We have and will file objections with the Bankruptcy Court as necessary for claims we believe should be disallowed. Claims we believe are allowable are included in Liabilities Subject to Compromise.

There can be no assurances regarding our ability to successfully develop, confirm and consummate one or more Chapter 11 plans or other alternative restructuring transactions, including a sale of all or substantially all of our assets, that satisfies the conditions of the Bankruptcy Code and is authorized by the Bankruptcy Court.

2015 CAPITAL PROGRAM

We incurred costs related to our capital program of $22.5 million during the first nine months of 2015. Our Board approved a capital program of $51 million for 2015; however, we could incur full year costs of up to $40 million in 2015. The reduction from the approved capital program in 2015 may be deferred into 2016.

In April 2015, pursuant to an amendment of our joint venture exploration agreement with Eni and with approval of the Bankruptcy Court, the U.S. Debtors agreed to drill and complete four additional wells in our West Texas Asset at a reduced working interest of approximately 35%. Substantially all of our costs to drill and complete these wells are included in our 2015 capital program; however, we expect to defer the completion of these wells into 2016.

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RESULTS OF OPERATIONS

Three Months Ended September 30, 2015 and 2014

The following discussion compares the results of operations for the three months ended September 30, 2015 and 2014, or the 2015 quarter and 2014 quarter, respectively. “Other U.S.” refers to the amounts for our operations in our West Texas Asset.

Revenue

We aggregate production revenue and realized cash gains (losses) on derivatives not treated as hedges in measuring revenue from our oil and gas production. Combining these items mirrors our view of the derivatives' usefulness, provides more comparability and is consistent with how management views and evaluates operating results.

Production Revenue and Realized Cash Gains on Derivatives by Operating Area:



	Natural Gas					NGL				Oil				Total
	2015			2014		2015		2014		2015		2014		2015			2014

	(in millions)
Barnett Shale	$	26.2		$	47.4	$	4.5	$	15.8	$	0.3	$	0.9	$	31.0		$	64.1
Other U.S.	—			—		—		—		0.7		0.6		0.7			0.6
Hedging	6.7			7.3		—		—		—		—		6.7			7.3
U.S.	32.9			54.7		4.5		15.8		1.0		1.5		38.4			72.0
Horseshoe Canyon	9.4			16.5		—		—		—		—		9.4			16.5
Horn River	(0.1		)	11.9		—		—		—		—		(0.1		)	11.9
Hedging	1.7			2.2		—		—		—		—		1.7			2.2
Canada	11.0			30.6		—		—		—		—		11.0			30.6
Consolidated production revenue	$	43.9		$	85.3	$	4.5	$	15.8	$	1.0	$	1.5	$	49.4		$	102.6

U.S. realized cash derivative gains ⁽¹⁾	$	2.7		$	1.9	$	—	$	0.2	$	—	$	—	$	2.7		$	2.1
Canada realized cash derivative gains ⁽¹⁾	2.1			0.8		—		—		—		—		2.1			0.8
Consolidated realized cash derivative gains	4.8			2.7		—		0.2		—		—		4.8			2.9
Consolidated production revenue and realized cash derivative gains ⁽²⁾	$	48.7		$	88.0	$	4.5	$	16.0	$	1.0	$	1.5	$	54.2		$	105.5

⁽¹⁾

On June 30, 2015, the remaining derivative position in our Canadian segment was transferred to the U.S. As this transaction was completed between consolidated entities, there were no realized gains in the consolidated financial statements. The Canada realized cash derivative gains represent the transferred value at June 30, 2015 as the derivative was terminated during the 2015 quarter. Changes to the derivative valuation subsequent to June 30, 2015 through the date of termination were included in U.S. realized cash derivative gains.

⁽²⁾

Realized cash derivative gains from derivatives not treated as hedges are included in net derivative gains. Changes in unrealized fair value of derivatives make up the remainder of net derivative gains as reported on our statement of income. Total revenue is comprised of production revenue, net derivative gains, sales of purchased natural gas and other revenue. See additional discussion below in Net Derivative Gains.

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Average Daily Production Volume by Operating Area:



	Natural Gas			NGL		Oil		Equivalent Total
	2015		2014	2015	2014	2015	2014	2015	2014

	(MMcfd)			(Bbld)		(Bbld)		(MMcfed)
Barnett Shale	105.2		128.4	3,476	5,913	89	102	126.6	164.5
Other U.S.	(0.2	)	0.1	—	—	179	72	0.9	0.5
U.S.	105.0		128.5	3,476	5,913	268	174	127.5	165.0
Horseshoe Canyon	44.4		45.8	1	3	—	—	44.4	45.8
Horn River	—		34.8	—	—	—	—	—	34.8
Canada	44.4		80.6	1	3	—	—	44.4	80.6
Consolidated	149.4		209.1	3,477	5,916	268	174	171.9	245.6

Average Realized Price by Operating Area:



	Natural Gas				NGL				Oil				Equivalent Total
	2015		2014		2015		2014		2015		2014		2015		2014

	(per Mcf)				(per Bbl)				(per Bbl)				(per Mcfe)
Barnett Shale	$	2.71	$	4.02	$	14.12	$	29.06	$	39.18	$	91.82	$	2.66	$	4.24
Other U.S.	2.34		1.38		—		—		43.51		89.08		8.07		12.84
Hedging	0.69		0.62		—		—		—		—		0.57		0.48
U.S.	3.40		4.63		14.12		29.06		42.07		90.69		3.27		4.74
Horseshoe Canyon	$	2.31	$	3.93	$	13.34	$	66.35	$	—	$	—	$	2.31	$	3.93
Horn River	—		3.71		—		—		—		—		—		3.71
Hedging	0.42		0.29		—		—		—		—		0.42		0.29
Canada	$	2.71	$	4.12	$	13.34	$	66.35	$	—	$	—	$	2.70	$	4.13
Consolidated production revenue	$	3.19	$	4.44	$	14.12	$	29.07	$	42.07	$	90.69	$	3.13	$	4.54

U.S. realized cash derivative gains	$	0.28	$	0.16	$	—	$	0.31	$	—	$	—	$	0.23	$	0.14
Canada realized cash derivative gains	0.51		0.11		—		—		—		—		0.51		0.11
Consolidated realized cash derivative gains	0.35		0.14		—		0.31		—		—		0.30		0.13
Consolidated production revenue and realized cash derivative gains	$	3.54	$	4.58	$	14.12	$	29.38	$	42.07	$	90.69	$	3.43	$	4.67

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The following table summarizes the changes in our natural gas, NGL and oil production revenue and realized cash derivative gains:



	Natural Gas			NGL			Oil			Total

	(in thousands)
Consolidated production revenue and realized cash derivative gains for the 2014 quarter	$	88,047		$	15,989		$	1,454		$	105,490
Volume variances	(21,660		)	(6,523		)	783			(27,400		)
Hedge revenue variances	(1,072		)	—			—			(1,072		)
Realized cash derivative variance ⁽¹⁾	2,088			(166		)	—			1,922
Price variances	(18,724		)	(4,784		)	(1,198		)	(24,706		)
Consolidated production revenue and realized cash derivative gains for the 2015 quarter	$	48,679		$	4,516		$	1,039		$	54,234


⁽¹⁾	This amount is also included in the production revenue and realized cash derivatives gains table above.

Our natural gas revenue, without the effects of realized cash derivative gains/losses or hedge revenue, decreased for the 2015 quarter from the 2014 quarter primarily due to lower volumes and a decrease in our realized price. Lower production volumes were primarily attributable to shut-in volumes in our Horn River Asset and, to a lesser extent, wells shut-in in our Barnett Shale Asset due to economics and natural well declines in our Barnett Shale Asset. Our realized cash derivative variance is primarily due to the monetization of our remaining derivative positions during the 2015 quarter. Consolidated production revenue and realized cash derivative gains from NGL revenue for the 2015 quarter decreased from the 2014 quarter due to lower realized prices, shut-in wells in our Barnett Shale Asset and natural decline of existing wells. Our oil revenue decreased for the 2015 quarter from the 2014 quarter due to lower realized priced partially offset by new well production in our West Texas Asset.

Our production revenue for the 2015 quarter and 2014 quarter was higher by $8.4 million and $9.5 million, respectively, because of our hedging activities. Effective December 31, 2012, we discontinued the use of hedge accounting. The net deferred hedge gain that was included in AOCI as of December 31, 2012 is being released into revenue from natural gas, NGL and oil production over the original term of the hedging relationship (through 2021).

All of our derivatives were terminated in 2015, which will result in no additional realized cash derivative revenue for future periods.

We expect our remaining 2015 production volumes to decline across all assets due to our limited 2015 capital program. Additionally, we are actively managing our current wells in this commodity price environment. We have shut-in wells in our Barnett Shale Asset that are not economic at current commodity prices and our current cost structure, which will continue to impact the variable components of our operating costs and our unit costs as fixed costs are allocated over lower production. We may, through the Chapter 11 process, improve our fixed and variable cost structure through renegotiation of certain contracts or other workaround solutions, which if successful, could lead to a restart of some or all of this production. However, if we are unsuccessful, we could shut-in additional wells, causing a potentially material portion of our production to remain off-line for an extended period.

In early March 2015, a third-party gathering and processing provider terminated service resulting in our Horn River Asset production being shut-in. We are exploring alternatives to gather and process our Horn River Asset production; however, we may not be able to find economic alternatives in the near-term, or at all, and production may remain shut-in for an extended period of time.

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Sales of Purchased Natural Gas and Costs of Purchased Natural Gas



	For the Three Months Ended September 30,
	2015		2014

	(in thousands)
Sales of purchased natural gas
Purchases from Eni	$	8,050	$	15,583
Purchases from others	292		1,077
Total	8,342		16,660
Costs of purchased natural gas sold
Purchases from Eni	8,053		15,582
Purchases from others	266		1,017
Total	8,319		16,599
Net sales and purchases of natural gas	$	23	$	61

Net Derivative Gains

The following table summarizes our net derivative gains:



	For the Three Months Ended September 30,
	2015			2014

	(in thousands)
Changes in unrealized fair value of natural gas derivatives	$	(4,536	)	$	39,854
Realized cash settlements of natural gas derivative gains	4,797			2,709
Changes in unrealized fair value of NGL derivatives	—			581
Realized cash settlements of NGL derivative gains	—			166
Derivative gains, net	$	261		$	43,310

Other Revenue



	For the Three Months Ended September 30,
	2015		2014

	(in thousands)
Midstream revenue from third parties
Canada	$	439	$	486
Texas	508		427
Total	$	947	$	913

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Operating Expense

Lease Operating



	For the Three Months Ended September 30,
	2015				2014

	(in thousands, except per unit amounts)
			Per Mcfe				Per Mcfe
Barnett Shale
Expense	$	4,995	$	0.43	$	9,193	$	0.61
Equity compensation expense	54		0.00		165		0.01
	$	5,049	$	0.43	$	9,358	$	0.62
Other U.S.
Expense	$	380	$	4.50	$	309	$	6.63
Equity compensation expense	11		0.13		48		1.03
	$	391	$	4.63	$	357	$	7.66
Total U.S.
Expense	$	5,375	$	0.46	$	9,502	$	0.63
Equity compensation expense	65		0.01		213		0.01
	$	5,440	$	0.47	$	9,715	$	0.64
Horseshoe Canyon
Expense	$	6,477	$	1.59	$	6,096	$	1.45
Equity compensation expense	199		0.05		415		0.10
	$	6,676	$	1.64	$	6,511	$	1.55
Horn River
Expense	$	390	$	—	$	950	$	0.30
Equity compensation expense	—		—		—		—
	$	390	$	—	$	950	$	0.30
Total Canada
Expense	$	6,867	$	1.68	$	7,046	$	0.95
Equity compensation expense	199		0.05		415		0.06
	$	7,066	$	1.73	$	7,461	$	1.01
Total Company
Expense	$	12,242	$	0.77	$	16,548	$	0.73
Equity compensation expense	264		0.02		628		0.03
	$	12,506	$	0.79	$	17,176	$	0.76

Lease operating expense for the 2015 quarter in our Barnett Shale Asset decreased in total primarily due to reduced volumes in the area as a result of natural well declines and our election to shut-in wells that are not economic at current commodity prices and our current cost structure. On a unit basis, the decrease is primarily due to lower water disposal expense and lower compression cost as higher-cost wells were shut-in. Additionally, workover costs were lowered due to reduced activity in this area. The increase in our Horseshoe Canyon Asset in total and on a unit basis is primarily driven by lower capitalization of overhead as drilling activity has decreased. Our Horn River Asset decrease in total is primarily due to the Asset being shut-in during the 2015 quarter. Costs incurred for the 2015 quarter in our Horn River Asset consist of maintenance costs while production is shut-in.

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Gathering, Processing and Transportation



	For the Three Months Ended September 30,
	2015				2014

	(in thousands, except per unit amounts)
			Per Mcfe				Per Mcfe
Barnett Shale	$	16,785	$	1.44	$	23,910	$	1.58
Other U.S.	7		0.08		1		0.01
Total U.S.	16,792		1.43		23,911		1.58
Horseshoe Canyon	741		0.18		784		0.19
Horn River	266		—		10,112		3.16
Total Canada	1,007		0.25		10,896		1.47
Total	$	17,799	$	1.13	$	34,807	$	1.54

Our Barnett Shale Asset GPT decreased on a unit basis for the 2015 quarter compared to the 2014 quarter primarily due to rejected natural gas transportation contracts and lower costs attendant to a renegotiated contract. In total, the decrease is also due to lower volumes in the 2015 quarter compared to the 2014 quarter. Our Horn River Asset GPT decreased as a result of the termination of a gathering and processing agreement in March 2015; however, we continued to incur expenses for unused firm capacity and operation expenses for our gathering system in our Horn River Asset. We are exploring alternatives to gather and process our Horn River Asset production; however, we may not be able to find economic alternatives in the near-term, or at all, and production may remain shut-in. Our Horn River Asset GPT includes unused firm capacity expenses of $0.1 million and $4.3 million for the 2015 quarter and the 2014 quarter, respectively.

Production and Ad Valorem Taxes



	For the Three Months Ended September 30,
	2015						2014

	(in thousands, except per unit amounts)
				Per Mcfe					Per Mcfe
Production taxes
Barnett Shale	$	447		$	0.04		$	1,110	$	0.07
Other U.S.	24			0.28			251		5.40
Total U.S.	471			0.04			1,361		0.09
Horseshoe Canyon	32			0.01			26		0.01
Horn River	—			—			—		—
Total Canada	32			0.01			26		0.00
Total production taxes	$	503		$	0.03		$	1,387	$	0.06
Ad valorem taxes
Barnett Shale	$	(470	)	$	(0.04	)	$	1,746	$	0.12
Other U.S.	(59		)	(0.69		)	9		0.20
Total U.S.	(529		)	(0.05		)	1,755		0.12
Horseshoe Canyon	645			0.16			732		0.17
Horn River	154			—			193		0.06
Total Canada	799			0.20			925		0.12
Total ad valorem taxes	270			0.02			2,680		0.12
Total	$	773		$	0.05		$	4,067	$	0.18

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Production taxes in our Barnett Shale Asset decreased primarily due to lower gas prices and lower volumes. Our accrual for ad valorem taxes in our Barnett Shale Asset was updated based on reduced assessed values during the 2015 quarter resulting in a decrease in accrued ad valorem taxes.

Depletion, Depreciation and Accretion



	For the Three Months Ended September 30,
	2015				2014

	(in thousands, except per unit amounts)
			Per Mcfe				Per Mcfe
Depletion
U.S.	$	5,050	$	0.43	$	7,654	$	0.50
Canada	2,643		0.65		1,080		0.15
Total depletion	7,693		0.49		8,734		0.39
Depreciation of other fixed assets
U.S.	$	1,364	$	0.12	$	1,554	$	0.10
Canada	1,264		0.31		2,262		0.30
Total depreciation	2,628		0.17		3,816		0.17
Accretion	1,329		0.08		1,419		0.06
Total	$	11,650	$	0.74	$	13,969	$	0.62

The U.S. depletion rate decreased as we reduced the depletable base due to a decrease in proved undeveloped reserves and related capital costs in light of our liquidity position and the uncertainty of sources of capital to fund a drilling and completions program at December 31, 2014. Total U.S. depletion also decreased due to lower production volumes. Canadian depletion for the 2015 quarter, when compared to the 2014 quarter, reflects an increase in the depletion rate primarily due to an increased depletable asset base partially offset by a decrease in production. The decrease in Canadian depreciation is primarily due to impairments taken in 2014 on the Fortune Creek gathering system. Following the impairment recognized in the 2015 quarter, we estimate that the U.S. depletion rate will be between $0.45 and $0.55 per Mcfe and that the Canadian depletion rate will be between $0.65 and $0.75 per Mcfe.

We will experience a reduction in our depletion rates in future periods as we expect to incur impairment expense due to prevailing prices subsequent to September 30, 2015 when compared to prices in the corresponding period of the prior year.

Impairment Expense

We perform quarterly ceiling tests to assess impairment of our oil and gas properties. We also assess our fixed assets reported outside the full-cost pool when circumstances indicate impairment may have occurred. The calculation of impairment expense is more fully described in Note 5 to the condensed consolidated financial statements in Item 1 of this Quarterly Report.

In the 2015 quarter, we recognized $150.8 million and $13.7 million in non-cash charges for impairment of our U.S. and Canadian oil and gas properties, respectively.

In performing our quarterly ceiling tests, we utilize first-day-of-the-month prices for the preceding 12 months. Based on the forecasted natural gas prices during the fourth quarter of 2015 compared to the fourth quarter of 2014, there is a significant likelihood of further impairment of oil and gas properties in both the U.S. and Canada. We estimate the December 31, 2015 first-day-of-the-month prices for the preceding 12 months by using the first of day pricing for October 2015 and the forward strip price for November and December 2015 as of October 27, 2015. Based on these assumptions, we estimated that the prices will be $2.62 per MMBtu for the Henry Hub natural gas price and $2.13 per MMBtu for AECO natural gas price. Based on these assumptions, we estimate that the U.S. oil and gas properties impairment could be up to $130 million and that the Canada oil and gas properties impairment could be up to $55 million for the fourth quarter of 2015. These ranges were estimated by holding all other inputs consistent with the third quarter of 2015 inputs except for prices. Therefore, these estimates strictly isolate the impact of commodity prices on our ceiling test.

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In the 2014 quarter, we recognized a non-cash impairment of $0.1 million related to midstream assets in our West Texas Asset.

General and Administrative



	For the Three Months Ended September 30,
	2015				2014

	(in thousands, except per unit amounts)
			Per Mcfe				Per Mcfe
Expense	$	8,355	$	0.53	$	6,026	$	0.27
Audit and accounting fees	684		0.04		458		0.02
Strategic transaction costs	157		0.01		1,885		0.08
Equity compensation	1,025		0.06		2,941		0.13
Total	$	10,221	$	0.64	$	11,310	$	0.50

General and administrative expense increased in the 2015 quarter compared to the 2014 quarter as a result of the 2014 quarter including a reduction to accrued employee incentive compensation and the 2015 quarter including employee retention compensation and lower capitalization of G&A expense. Partially offsetting these increases was a decrease in salaries resulting from a reduction in force in February 2015 and lower professional fees during the 2015 quarter. Strategic transaction costs relating to asset marketing and organizational alternatives have decreased for the 2015 quarter as post-bankruptcy activity is included in Reorganization Items, net. The decrease in equity compensation is primarily due to employee stock grants not being issued in 2015.

Other Income (Expense)

In the 2015 and 2014 quarter, the Canadian foreign currency exchange rate resulted in recognized losses of $0.7 million and $2.8 million, respectively.

Fortune Creek Accretion

KKR’s contribution is shown as Partnership liability in the condensed consolidated balance sheet, and we recognize accretion expense to reflect the rate of return earned by KKR via its investment.

Interest Expense



	For the Three Months Ended September 30,
	2015			2014

	(in thousands)
Interest costs on debt outstanding	$	2,739		$	38,736
Add:
Fees paid on letters of credit outstanding	44			89
Non-cash interest ⁽¹⁾	660			2,601
Total interest costs incurred	3,443			41,426
Less:
Interest capitalized	(251		)	(1,527		)
Interest expense	$	3,192		$	39,899


⁽¹⁾	Represents amortization of deferred financing costs and original issue discount net of interest swap settlement amortization.

Interest costs incurred for the 2015 quarter were lower when compared to the 2014 quarter primarily because we discontinued the accrual and payment of interest on the Second Lien Term Loan, Second Lien Notes, Senior Notes due 2019, Senior Notes due 2021 and Senior Subordinated Notes from and after the Petition Date.

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Capitalized interest has decreased for the 2015 quarter when compared to the 2014 quarter as our unevaluated oil and natural gas property balances have decreased due to movement into the respective country cost center as areas become evaluated and proved reserves established or impairment determined.

Reorganization Items, Net



	For the Three Months Ended September 30, 2015

	(in thousands)
Professional fees	$	8,352
Terminated contracts	(469		)
Reorganization items, net	$	7,883

Professional fees included in Reorganization Items, net are for post-petition expenses. The reduction in the terminated contracts is due to an adjustment to our previously accrued amount based on claims filed.

Income Taxes

The effective tax rates for the three months ended September 30, 2015 and 2014 are as follows:



	For the Three Months Ended September 30,
	2015			2014

	(in thousands)
Income tax (benefit) expense - U.S.	$	2,330		$	(4,873	)
Effective tax rate - U.S.	(2.0		)%	(48.0		)%
Income tax (benefit) expense - Canada	$	(178	)	$	(66	)
Effective tax rate - Canada	1.0		%	(1.0		)%
Income tax (benefit) expense - total	$	2,152		$	(4,939	)
Effective tax rate - total	(1.2		)%	(26.2		)%

Income tax expense for the 2015 quarter included increases in the U.S. and Canadian valuation allowances of $36.2 million and $0.5 million, respectively. We have a full valuation allowance in both the U.S. and Canada. Deferred income tax recognized for the 2015 and 2014 quarters is a result of hedge gains previously deferred in AOCI being realized during the quarter and the net tax impact being recognized.

In June 2015, the Alberta government passed regulation to increase the provincial tax rate by 2% with an effective date of July 2015. We adjusted our rates based on this change during the quarter ended June 30, 2015.

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RESULTS OF OPERATIONS

Nine Months Ended September 30, 2015 and 2014

The following discussion compares the results of operations for the nine months ended September 30, 2015 and 2014, or the 2015 period and 2014 period, respectively. “Other U.S.” refers to the combined amounts for our operations in our Niobrara Asset and West Texas Asset. The impact of the Southwestern Transaction was immaterial for further disaggregation.

Revenue

Production Revenue and Realized Cash Gains (Losses) on Derivatives by Operating Area:



	Natural Gas					NGL					Oil				Total
	2015		2014			2015		2014			2015		2014		2015		2014

	(in millions)
Barnett Shale	$	83.2	$	148.0		$	17.2	$	51.1		$	1.4	$	3.7	$	101.8	$	202.8
Other U.S.	0.1		—			—		—			1.9		1.2		2.0		1.2
Hedging	19.3		22.1			—		—			—		—		19.3		22.1
U.S.	102.6		170.1			17.2		51.1			3.3		4.9		123.1		226.1
Horseshoe Canyon	28.2		53.5			—		—			—		—		28.2		53.5
Horn River	4.8		46.1			—		—			—		—		4.8		46.1
Hedging	5.8		6.5			—		—			—		—		5.8		6.5
Canada	38.8		106.1			—		—			—		—		38.8		106.1
Consolidated production revenue	$	141.4	$	276.2		$	17.2	$	51.1		$	3.3	$	4.9	$	161.9	$	332.2

U.S. realized cash derivative gains (losses) ⁽¹⁾	$	115.3	$	(11.8	)	$	—	$	(2.3	)	$	—	$	—	$	115.3	$	(14.1	)
Canada realized cash derivative gains (losses) ⁽¹⁾	53.0		(0.7		)	—		—			—		—		53.0		(0.7		)
Consolidated realized cash derivative gains (losses)	168.3		(12.5		)	—		(2.3		)	—		—		168.3		(14.8		)
Consolidated production revenue and realized cash derivative gains (losses) ⁽²⁾	$	309.7	$	263.7		$	17.2	$	48.8		$	3.3	$	4.9	$	330.2	$	317.4

⁽¹⁾

On June 30, 2015, the remaining derivative position in our Canadian segment was transferred to the U.S. As this transaction was completed between consolidated entities, there were no realized gains in the consolidated financial statements. The Canada realized cash derivative gains (losses) represent the transferred value at June 30, 2015 as the derivative was terminated during the 2015 period. Changes to the derivative valuation subsequent to June 30, 2015 through the date of termination were included in U.S. realized cash derivative gains (losses).

⁽²⁾

Realized cash derivative gains (losses) from derivatives not treated as hedges are included in net derivative gains (losses). Changes in unrealized fair value of derivatives make up the remainder of net derivative gains (losses) as reported on our statement of income. Total revenue is comprised of production revenue, net derivative gains (losses), sales of purchased natural gas and other revenue. See additional discussion below in Net Derivative Gains (Losses).

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Average Daily Production Volume by Operating Area:



	Natural Gas		NGL		Oil		Equivalent Total
	2015	2014	2015	2014	2015	2014	2015	2014

	(MMcfd)		(Bbld)		(Bbld)		(MMcfed)
Barnett Shale	112.0	123.4	4,018	6,195	115	141	136.8	161.4
Other U.S.	0.2	—	—	—	151	49	1.1	0.3
U.S.	112.2	123.4	4,018	6,195	266	190	137.9	161.7
Horseshoe Canyon	45.3	46.7	2	5	—	—	45.3	46.8
Horn River	8.1	40.5	—	—	—	—	8.1	40.5
Canada	53.4	87.2	2	5	—	—	53.4	87.3
Consolidated	165.6	210.6	4,020	6,200	266	190	191.3	249.0

Average Realized Price by Operating Area:



	Natural Gas					NGL					Oil				Equivalent Total
	2015		2014			2015		2014			2015		2014		2015		2014

	(per Mcf)					(per Bbl)					(per Bbl)				(per Mcfe)
Barnett Shale	$	2.71	$	4.39		$	15.65	$	30.24		$	44.23	$	94.98	$	2.73	$	4.61
Other U.S.	2.25		—			—		—			46.17		89.53		6.67		12.04
Hedging	0.63		0.66			—		—			—		—		0.51		0.50
U.S.	$	3.35	$	5.05		$	15.65	$	30.24		$	45.33	$	93.58	$	3.27	$	5.12
Horseshoe Canyon	$	2.28	$	4.19		$	18.28	$	37.39		$	—	$	—	$	2.28	$	4.19
Horn River	2.18		4.18			—		—			—		—		2.18		4.18
Hedging	0.40		0.27			—		—			—		—		0.40		0.27
Canada	$	2.66	$	4.46		$	18.28	$	37.39		$	—	$	—	$	2.66	$	4.46
Consolidated production revenue	$	3.13	$	4.80		$	15.65	$	30.25		$	45.33	$	93.58	$	3.10	$	4.89

U.S. realized cash derivative gains (losses)	$	3.76	$	(0.35	)	$	—	$	(1.33	)	$	—	$	—	$	3.06	$	(0.32	)
Canada realized cash derivative gains (losses)	3.63		(0.03		)	—		—			—		—		3.63		(0.03		)
Consolidated realized cash derivative gains (losses)	$	3.72	$	(0.22	)	$	—	$	(1.33	)	$	—	$	—	$	3.22	$	(0.22	)
Consolidated production revenue and realized cash derivative gains (losses)	$	6.85	$	4.58		$	15.65	$	28.92		$	45.33	$	93.58	$	6.32	$	4.67

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The following table summarizes the changes in our natural gas, NGL and oil production revenue and realized cash derivative gains:



	Natural Gas			NGL			Oil			Total

	(in thousands)
Consolidated production revenue and realized cash derivative gains for the 2014 period	$	263,657		$	48,939		$	4,860		$	317,456
Volume variances	(52,776		)	(18,001		)	1,925			(68,852		)
Hedge revenue variances	(3,562		)	—			—			(3,562		)
Realized cash derivative variance ⁽¹⁾	180,721			2,253			—			182,974
Price variances	(78,377		)	(16,021		)	(3,500		)	(97,898		)
Consolidated production revenue and realized cash derivative gains for the 2015 period	$	309,663		$	17,170		$	3,285		$	330,118


⁽¹⁾	This amount is also included in the production revenue and realized cash derivatives gains table above.

Our natural gas revenue, without the effects of realized cash derivative gains/losses or hedge revenue, decreased for the 2015 period from the 2014 period primarily due to lower volumes and a decrease in our realized price. Lower production volumes were primarily attributable to shut-in volumes in our Horn River Asset and, to a lesser extent, wells shut-in in our Barnett Shale Asset due to economics and natural well declines in our Barnett Shale Asset, partially offset by new well production in our Barnett Shale Asset. Our realized cash derivative variance is due to the receipt of cash related to our gas swaps terminated during the 2015 period. Consolidated production revenue and realized cash derivative gains from NGL revenue for the 2015 period decreased from the 2014 period due to lower realized prices, shut-in wells in our Barnett Shale Asset and declining well production, partially offset by the 2014 period including a realized cash derivative loss. Our oil revenue decreased for the 2015 period from the 2014 period due to lower realized prices partially offset by new well production in our West Texas Asset.

Our production revenue for the 2015 period and 2014 period was higher by $25.1 million and $28.6 million, respectively, because of our hedging activities. Effective December 31, 2012, we discontinued the use of hedge accounting. The net deferred hedge gain that was included in AOCI as of December 31, 2012 is being released into revenue from natural gas, NGL and oil production over the original term of the hedging relationship (through 2021).

All of our derivatives were terminated in 2015, which will result in no additional realized cash derivative revenue for future periods.

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Sales of Purchased Natural Gas and Costs of Purchased Natural Gas



	For the Nine Months Ended September 30,
	2015		2014

	(in thousands)
Sales of purchased natural gas
Purchases from Eni	$	28,717	$	50,627
Purchases from others	1,204		2,774
Total	29,921		53,401
Costs of purchased natural gas sold
Purchases from Eni	28,717		50,604
Purchases from others	1,146		2,701
Total	29,863		53,305
Net sales and purchases of natural gas	$	58	$	96

Net Derivative Gains (Losses)

The following table summarizes our net derivative gains and losses:



	For the Nine Months Ended September 30,
	2015			2014

	(in thousands)
Changes in unrealized fair value of natural gas derivatives	$	(140,380	)	$	(1,948	)
Realized cash settlements of natural gas derivative gains (losses)	168,243			(12,478		)
Changes in unrealized fair value of NGL derivatives	—			1,599
Realized cash settlements of NGL derivative losses	—			(2,253		)
Derivative gains (losses), net	$	27,863		$	(15,080	)

Certain of our derivative positions were restructured or terminated in January and March 2015 prior to our Chapter 11 filings and subsequently in August 2015. Additionally, our Chapter 11 filings in March 2015 represented an event of default under our derivative agreements resulting in a termination right by counterparties on the remaining derivative position at March 17, 2015. The resulting terminations resulted in settlements of $99.4 million and $39.5 million for the U.S. and Canada, respectively, during the 2015 period. As a result, we no longer have any derivatives.

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Other Revenue



	For the Nine Months Ended September 30,
	2015		2014

	(in thousands)
Midstream revenue from third parties
Canada	$	1,306	$	1,585
Texas	6,154		1,223
Total	$	7,460	$	2,808

In the 2015 period, we recognized previously deferred midstream revenue of $4.9 million related to funds received from a third party in prior years in exchange for a preferential gathering rate. We will recognize the remaining $10.2 million between 2016 and 2018. The amounts to be recognized in each period are dependent on the estimated volumes remaining to be delivered under the terms of the contract.

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Operating Expense

Lease Operating



	For the Nine Months Ended September 30,
	2015				2014

	(in thousands, except per unit amounts)
			Per Mcfe				Per Mcfe
Barnett Shale
Expense	$	18,215	$	0.49	$	29,638	$	0.67
Equity compensation expense	254		0.01		359		0.01
	$	18,469	$	0.50	$	29,997	$	0.68
Other U.S.
Expense	$	1,320	$	4.34	$	1,339	$	15.17
Equity compensation expense	46		0.15		145		1.64
	$	1,366	$	4.49	$	1,484	$	16.81
Total U.S.
Expense	$	19,535	$	0.52	$	30,977	$	0.70
Equity compensation expense	300		0.01		504		0.01
	$	19,835	$	0.53	$	31,481	$	0.71
Horseshoe Canyon
Expense	$	18,213	$	1.47	$	19,456	$	1.52
Equity compensation expense	663		0.05		1,092		0.09
	$	18,876	$	1.52	$	20,548	$	1.61
Horn River
Expense	$	1,052	$	0.47	$	2,593	$	0.23
Equity compensation expense	—		—		—		—
	$	1,052	$	0.47	$	2,593	$	0.23
Total Canada
Expense	$	19,265	$	1.32	$	22,049	$	0.93
Equity compensation expense	663		0.05		1,092		0.05
	$	19,928	$	1.37	$	23,141	$	0.98
Total Company
Expense	$	38,800	$	0.74	$	53,026	$	0.78
Equity compensation expense	963		0.02		1,596		0.02
	$	39,763	$	0.76	$	54,622	$	0.80

Lease operating expense for the 2015 period in our Barnett Shale Asset decreased in total primarily due to reduced volumes in the area as a result of natural well declines and our election to shut-in wells that are not economic at current commodity prices and our current cost structure. On a unit basis, the decrease is primarily due to reduced gas lift expense resulting from the receipt of a payment from a partner in respect of gas lift services as well as a reduction in gas lift rates from a third-party service provider and lower water disposal expense as shut-in wells were higher water producing wells. These decreases were partially offset by lower recoveries due to shut-in wells and an update in the 2015 period to allocate a higher percentage of these recoveries to general and administrative expense. The decrease in our Horseshoe Canyon Asset in total and on a unit basis is primarily driven by foreign currency impacts. Our Horn River Asset decrease in total is primarily due to the asset being shut-in beginning in March 2015.

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Gathering, Processing and Transportation



	For the Nine Months Ended September 30,
	2015				2014

	(in thousands, except per unit amounts)
			Per Mcfe				Per Mcfe
Barnett Shale	$	55,437	$	1.48	$	68,947	$	1.57
Other U.S.	29		0.10		1		0.02
Total U.S.	55,466		1.47		68,948		1.56
Horseshoe Canyon	2,281		0.18		2,531		0.20
Horn River	7,523		3.39		31,032		2.81
Total Canada	9,804		0.67		33,563		1.41
Total	$	65,270	$	1.25	$	102,511	$	1.51

Our Barnett Shale Asset GPT decreased on a unit basis for the 2015 period compared to the 2014 period primarily due to rejected natural gas transportation contracts and lower costs attendant to a renegotiated contract, effective as of April 2015. In total, the decrease is also due to lower volume in the 2015 period compared to the 2014 period.

Our Horn River Asset GPT decreased in total for the 2015 period compared to the 2014 period as a result of the termination of a gathering and processing agreement in March 2015. After the termination date, expenses related to this contract are recognized in Other Expense. We are exploring alternatives to gather and process our Horn River Asset production; however, we may not be able to find economic alternatives in the near-term, or at all, and production may remain shut-in. On a unit basis, the increase is primarily due to lower volumes in the 2015 period compared to the 2014 period. Our Horn River Asset GPT includes unused firm capacity expenses of $3.9 million and $11.0 million for the 2015 period and the 2014 period, respectively.

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Production and Ad Valorem Taxes



	For the Nine Months Ended September 30,
	2015				2014

	(in thousands, except per unit amounts)
			Per Mcfe				Per Mcfe
Production taxes
Barnett Shale	$	1,416	$	0.04	$	3,365	$	0.08
Other U.S.	87		0.29		260		2.95
Total U.S.	1,503		0.04		3,625		0.08
Horseshoe Canyon	156		0.01		128		0.01
Horn River	—		—		—		—
Total Canada	156		0.01		128		0.01
Total production taxes	$	1,659	$	0.03	$	3,753	$	0.06
Ad valorem taxes
Barnett Shale	$	3,777	$	0.10	$	5,938	$	0.13
Other U.S.	102		0.34		110		1.25
Total U.S.	3,879		0.10		6,048		0.14
Horseshoe Canyon	2,028		0.16		2,182		0.17
Horn River	480		0.22		574		0.05
Total Canada	2,508		0.17		2,756		0.12
Total ad valorem taxes	6,387		0.12		8,804		0.13
Total	$	8,046	$	0.15	$	12,557	$	0.18

Production taxes in our Barnett Shale Asset decreased primarily due to lower commodity pricing and lower volumes during the 2015 period. Ad valorem taxes in our Barnett Shale Asset decreased as assessed values were reduced.

Depletion, Depreciation and Accretion



	For the Nine Months Ended September 30,
	2015				2014

	(in thousands, except per unit amounts)
			Per Mcfe				Per Mcfe
Depletion
U.S.	$	16,210	$	0.43	$	22,263	$	0.50
Canada	11,287		0.77		4,582		0.19
Total depletion	27,497		0.53		26,845		0.39
Depreciation of other fixed assets
U.S.	$	4,247	$	0.11	$	4,769	$	0.11
Canada	4,030		0.28		6,759		0.28
Total depreciation	8,277		0.16		11,528		0.17
Accretion	4,019		0.08		4,211		0.06
Total	$	39,793	$	0.77	$	42,584	$	0.62

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an increase in the depletion rate primarily due to an increased depletable asset base partially offset by a decrease in production. The decrease in Canadian depreciation is primarily due to impairments taken in 2014 on the Fortune Creek gathering system. Following the impairment recognized in the 2015 quarter, we estimate that the U.S. depletion rate will be between $0.45 and $0.55 per Mcfe and that the Canadian depletion rate will be between $0.65 and $0.75 per Mcfe.

Impairment Expense

In the 2015 period, we recognized $150.8 million and $91.1 million in non-cash charges for impairment of our U.S. and Canadian oil and gas properties, respectively.

General and Administrative



	For the Nine Months Ended September 30,
	2015				2014

	(in thousands, except per unit amounts)
			Per Mcfe				Per Mcfe
Expense	$	26,067	$	0.50	$	22,816	$	0.33
Audit and accounting fees	2,006		0.04		1,906		0.03
Strategic transaction costs	7,052		0.13		5,843		0.09
Equity compensation	4,187		0.08		7,550		0.11
Total	$	39,312	$	0.75	$	38,115	$	0.56

The increase in general and administrative expense in the 2015 period is primarily due to lower capitalization of G&A expense and an increase in employee retention compensation, partially offset by lower salaries resulting from a reduction in force in February 2015. Strategic transaction costs relating to asset marketing and organizational alternatives increased for the 2015 period as activity increased prior to our Chapter 11 filing compared to the 2014 period. Post-bankruptcy related expenses are included in Reorganization Items, net. The decrease in equity compensation is primarily due to the 2014 period including stock-based executive incentive compensation payments and no grants being issued in 2015.

Other Income (Expense)

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Horn River Asset being shut-in. Further, a termination notice was issued effective March 19, 2015. We are exploring alternatives to gather and process our Horn River Asset production; however, we may not be able to find economic alternatives in the near-term, or at all, and production may remain shut-in.

In connection with this Canadian gathering and processing contract, we had previously issued a letter of credit in the amount of C$33 million. Upon termination, the third party drew down the full face amount of the letter of credit. We do not believe the third party was legally entitled to draw down the entire amount of the letter of credit and we have reserved all of our rights, entitlements and remedies in that regard. The C$33 million draw is shown as a reduction to amounts outstanding under the contract for services provided prior to the termination and the remainder is recognized as Other Expense.

In the 2015 and 2014 period, the Canadian foreign currency exchange rate resulted in recognized losses of $4.5 million and $2.0 million, respectively.

Fortune Creek Accretion

KKR’s contribution is shown as Partnership liability in the condensed consolidated balance sheet, and we recognize accretion expense to reflect the rate of return earned by KKR via its investment. The decrease in Fortune Creek accretion is primarily due to decreases in the U.S.-Canadian exchange rate.

Interest Expense



	For the Nine Months Ended September 30,
	2015			2014

	(in thousands)
Interest costs on debt outstanding	$	40,138		$	116,787
Add:
Fees paid on letters of credit outstanding	244			235
Net expense paid on debt refinancing	—			682
Non-cash interest ⁽¹⁾	3,897			8,441
Total interest costs incurred	44,279			126,145
Less:
Interest capitalized	(742		)	(4,218		)
Interest expense	$	43,537		$	121,927


⁽¹⁾	Represents amortization of deferred financing costs and original issue discount net of interest swap settlement amortization. The 2014 period includes $0.6 million relating to the early redemption of our Senior Notes due 2015 and Senior Notes due 2016 and the reduction of the Combined Credit Agreements.

Interest costs incurred for the 2015 period were lower when compared to the 2014 period primarily because we discontinued the accrual of interest on the Second Lien Term Loan, Second Lien Notes, Senior Notes due 2019, Senior Notes due 2021 and Senior Subordinated Notes from and after the Petition Date.

Capitalized interest has decreased for the 2015 period when compared to the 2014 period as our unevaluated oil and natural gas property balances have decreased due to movement into the respective country cost center as areas become evaluated and proved reserves established or impairment determined.

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Reorganization Items, Net



	For the Nine Months Ended September 30, 2015

	(in thousands)
Professional fees	$	22,895
Deferred financing costs and unamortized discounts	59,983
Deferred interest rate swap gains	(2,314		)
Terminated contracts	68,004
Reorganization items, net	$	148,568

Income Taxes

The effective tax rates for the nine months ended September 30, 2015 and 2014 are as follows:



	For the Nine Months Ended September 30,
	2015			2014

	(in thousands)
Income tax (benefit) expense - U.S.	$	6,493		$	213
Effective tax rate - U.S.	(2.0		)%	(0.3		)%
Income tax (benefit) expense - Canada	$	(657	)	$	868
Effective tax rate - Canada	0.5		%	24.8		%
Income tax (benefit) expense - total	$	5,836		$	1,081
Effective tax rate - total	(1.3		)%	(1.5		)%

Income tax expense for the 2015 period included an increase in the U.S. and Canadian valuation allowances of $85.1 million and $35.8 million, respectively. We have a full valuation allowance in both the U.S. and Canada. Deferred income tax recognized for the 2015 and 2014 periods is a result of hedge gains previously deferred in AOCI being realized during the period and the net tax impact being recognized.

Quicksilver Resources Inc. and its Restricted Subsidiaries

Information about Quicksilver and our restricted and unrestricted subsidiaries is included in Note 5 to our condensed consolidated interim financial statements included in Item 1 of this Quarterly Report.

The combined results of operations for Quicksilver and our restricted subsidiaries are substantially similar to our consolidated results of operations, which are discussed above under “Results of Operations,” except for Fortune Creek accretion expense. The combined financial position of Quicksilver and our restricted subsidiaries and our consolidated financial position are materially the same except for balances related to Fortune Creek which were included in the consolidated financial position as of September 30, 2015. The combined operating cash flows, financing cash flows and investing cash flows for Quicksilver and our restricted subsidiaries are substantially similar to our consolidated operating cash flows, financing cash flows and investing cash flows, which are discussed below in “Cash Flow Activity,” except for cash flows associated with the operations and development of Fortune Creek.

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LIQUIDITY, CAPITAL RESOURCES AND FINANCIAL POSITION

Cash Flow Activity

Our financial condition and results of operations, including our liquidity and profitability, are significantly affected by the prices that we realize for our natural gas, NGL and oil production and the volumes of natural gas, NGLs and oil that we produce.

The natural gas, NGLs and oil that we produce are commodity products for which established trading markets exist. Accordingly, product pricing is generally influenced by the relationship between supply and demand for these products. Product supply is affected primarily by fluctuations in production volumes, and product demand is affected by the state of the economy in general, the availability and price of alternative fuels and a variety of other factors. Prices for our products historically have been volatile, and we have no meaningful influence over the timing and extent of price changes for our products.

The volumes that we produce may be significantly affected by the rates at which we acquire leaseholds and other mineral interests and explore, exploit and develop our leasehold and other mineral interests through drilling and production activities. These activities require substantial capital expenditures, and our ability to fund these activities through cash flow from our operations, borrowings and other sources may be affected by multiple factors discussed further in the Liquidity and Capital Resources section below.

In 2015, all of our derivatives were terminated either by us or the counterparties to such derivatives in anticipation or as a result of our Chapter 11 filings or through negotiations during the Chapter 11 proceedings. The proceeds of the 2015 terminated derivatives and related interest were $139.1 million. We have used all of the proceeds from these terminated derivatives to pay down amounts outstanding under our Combined Credit Agreements.

The following summarizes our cash flow activity for the 2015 period and 2014 period:



	For the Nine Months Ended September 30,
	2015			2014

	(in thousands)
Net cash provided by (used in) operating activities	$	111,869		$	(4,983	)
Net cash provided by (used in) investing activities	(22,029		)	152,220
Net cash provided by (used in) financing activities	(143,946		)	9,769

Operating Cash Flows

Net cash provided by operating activities for the 2015 period increased from the 2014 period primarily due to the terminated derivatives.

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Investing Cash Flows

Costs incurred for property, plant and equipment for the 2015 period and 2014 period were as follows:



	United States		Canada		Consolidated

	(in thousands)
For the Nine Months Ended September 30, 2015
Exploration and development	$	19,615	$	2,557	$	22,172
Midstream	—		48		48
Administrative	307		18		325
Total	$	19,922	$	2,623	$	22,545
For the Nine Months Ended September 30, 2014
Exploration and development	$	85,814	$	20,924	$	106,738
Midstream	83		—		83
Administrative	310		453		763
Total	$	86,207	$	21,377	$	107,584

Costs incurred reflect the activity of the 2015 capital program, while capital expenditures shown in the condensed consolidated statement of cash flows also reflect the related changes in working capital. Changes in working capital are driven by changes in accounts payable from prior year activities. The decrease in capital expenditures in the 2015 period compared to the 2014 period is due to the bankruptcy process and the current commodity pricing environment.

Financing Cash Flows

In March 2015, a third-party service provider drew down the full face amount of a C$33 million letter of credit in connection with their termination of a Canadian gathering and processing contract, see additional discussion below in “Contractual Obligations and Commercial Commitments.” Additionally, we had repayments of debt in the 2015 period as we used proceeds from derivative terminations to reduce outstanding amounts under our Combined Credit Agreements. During the 2015 period, we made adequate protection payments of $31.6 million, to holders of our Second Lien Term Loan and Second Lien Notes, which are treated as a principal payment rather than as interest expense. Distributions of Fortune Creek partnership funds of $1.4 million and $37.1 million were paid in the 2015 period and the 2014 period, respectively, to our partner based on our partner's preferential distribution rights.

Liquidity and Borrowing Capacity

Our sources of liquidity and capital resources historically have been cash flow from operations, proceeds from assets sales, borrowings under the Combined Credit Agreements, and issuances of debt securities. In 2015, all of our derivative positions were terminated, which will significantly reduce our operating cash flow in future periods given current commodity prices. Proceeds and interest thereon from these terminated derivative positions of $139.1 million were used to reduce amounts outstanding under our Combined Credit Agreements. Our Chapter 11 filings constituted an event of default under the Combined Credit Agreements and all borrowings and other fees under the Combined Credit Agreements became immediately due and payable. As a result, we no longer have any liquidity available to us under the Combined Credit Agreements. The ability of the lenders under the Combined Credit Agreements to seek remedies to enforce their rights under the agreements against the U.S. Debtors was automatically stayed as a result of the Chapter 11 filings, and the lenders’ rights of enforcement against the U.S. Debtors are subject to the applicable provisions of the Bankruptcy Code.

Since the Chapter 11 filings, our principal sources of liquidity have been limited to cash flow from operations and cash on hand. As of September 30, 2015, we held cash and cash equivalents of $175.7 million. Although we believe our cash flow from operations and cash on hand will be adequate to meet the short‑term operating costs of our existing business, there are no assurances that our cash flow from operations and cash on hand will be sufficient to continue to fund our operations or to allow us to continue as a going concern until a Chapter 11 plan is confirmed by the Bankruptcy Court or other alternative restructuring transaction is approved by the Bankruptcy Court and consummated. Our long-term liquidity requirements, the adequacy of our capital

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resources and our ability to continue as a going concern are difficult to predict at this time and ultimately cannot be determined until a Chapter 11 plan has been confirmed, if at all, by the Bankruptcy Court. In addition to the cash requirements necessary to fund ongoing operations, we have incurred and expect that we will continue to incur significant professional fees and other costs in connection with the administration of the Chapter 11 proceedings.

If our future sources of liquidity are insufficient, we could face substantial liquidity constraints and be unable to continue as a going concern and will likely be required to significantly further reduce, delay or eliminate capital expenditures, implement further cost reductions, seek other financing alternatives or seek the sale of some or all of our assets. If we further limit, defer or eliminate our 2015 capital expenditure plan or are unsuccessful in developing reserves and adding production through our capital program or our cost-cutting efforts are too overreaching, the value of our oil and natural gas properties and our financial condition and results of operations could be adversely affected.

Financial Position

The following impacted our balance sheet as of September 30, 2015, compared to our balance sheet as of December 31, 2014:

•

Cash and cash equivalents decreased $47.9 million as we have used cash for investing activities and payment of adequate protection payments, which are treated as a reduction of our outstanding debt and included in financing activities and payment of reorganization expense. Additionally, all cash proceeds received from terminated derivatives during the 2015 period were used to repay our Combined Credit Agreements.


•	The valuation of our current and non-current derivative assets was $149.6 million lower on a net basis, which was primarily due to the termination of all of our derivative positions in the 2015 period.


•	Our net property, plant and equipment balance decreased $288.0 million primarily due to DD&A incurred of $35.8 million, impairment expense of $241.9 million and $32.7 million related to U.S.-Canadian exchange rate changes. Offsetting these decreases, we incurred capital costs of $22.5 million during the 2015 period.

•

Other non-current assets decreased $26.2 million primarily due to the recognition as expense at the Petition Date of $23.3 million of deferred financing costs and unamortized discounts for the Second Lien Term Loan, Second Lien Notes, Senior Notes due 2019, Senior Notes due 2021 and Senior Subordinated Notes as we believe these debt instruments may be impacted by the bankruptcy reorganization process, amortization of deferred financing costs of $2.9 million and U.S.-Canadian exchange rate changes.

•

Current portion of long-term debt decreased $1.88 billion primarily from the reclassification of the majority of our debt to Liabilities Subject to Compromise. The remainder of the decrease was due to net payments under the Combined Credit Agreements of $110.8 million, changes to the U.S.-Canadian exchange rate resulting in a decrease of $6.8 million and recognition of $0.5 million of interest rate swaps, partially offset by $1.3 million of amortized discounts.


•	Our accrued liabilities decreased $43.1 million, primarily due to the reclassification of the majority of our previously accrued interest to Liabilities Subject to Compromise.

Contractual Obligations and Commercial Commitments

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of credit and we have reserved all of our rights, entitlements and remedies in that regard. The C$33 million draw is shown as a reduction to amounts outstanding under the contract for services provided prior to the termination and the remaining $21.5 million is recognized as Other Expense. At the present time, we cannot predict the ultimate outcome of this matter, including whether some or all of the C$33 million drawn on the letter of credit will be payable to us or whether any additional amounts will have to be paid related to the termination of the contract.

QRCI did not make an approximately C$1.6 million payment due at the end of June 2015 and has not made subsequent monthly payments of the same amount pursuant to the gathering agreement with Fortune Creek. As a result, among other things: (i) Fortune Creek may discontinue transporting QRCI's gas until all amounts owing are repaid (although, as previously disclosed, production was previously shut-in due to the termination of a third-party gathering and processing agreement in March 2015); (ii) if the non-payment continues for more than 90 days after written demand therefor, subject to certain existing contracts for the sale of gas, Fortune Creek may enforce the lien granted by QRCI to Fortune Creek on the natural gas belonging to QRCI while it is in the Maxhamish Pipeline and in Fortune Creek's possession; (iii) Fortune Creek has certain set-off rights against QRCI; (iv) if the non-payment continues for 180 days (or 60 days following written notice by the other partner), we will not be entitled to receive partnership distributions or vote with respect to partnership matters until the non-payment is cured and Fortune Creek may be dissolved or our partnership interest in Fortune Creek may be purchased by the other partner; and (v) the operating agreement could be terminated by Fortune Creek. We have not received any written notices regarding the past due amounts. Past due amounts under the gathering agreement bear interest compounded monthly at prime plus 2%. We are in discussions with KKR in connection with the issues related to Fortune Creek; however, we may not reach a resolution in the near-term, or at all.

Our Chapter 11 filings constituted an event of default under the Combined Credit Agreements, Second Lien Term Loan, the Second Lien Notes, the Senior Notes due 2019, the Senior Notes due 2021, and the Senior Subordinated Notes. All principal, interest and other amounts under each of these debt instruments became immediately due and payable at that time.

On April 15 and May 8, 2015, the Bankruptcy Court issued orders allowing us to reject certain executory contracts effective March 17 and April 1, 2015 and the total estimated allowable claim under these contracts has been included in Liabilities Subject to Compromise and Reorganization Items, net as appropriate. The reductions primarily impacted our GPT contracts and reduced our total payments due over the life of the contracts as of the date the contracts were rejected by approximately $39 million and reduced our volume obligations under these contracts by approximately 177,000 MMcfe.

We renegotiated an NGL GPT contract in our Barnett Shale Asset effective April 2015, which reduced our GPT obligations by approximately $100 million and reduced our volume obligations under these contracts by approximately 260,000 MMcfe over the life of the contract.

As of September 30, 2015, other than the changes discussed above, there have been no significant changes to our contractual obligations and commitments as reported in our 2014 Annual Report on Form 10-K.

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Critical Accounting Estimates

Management’s discussion and analysis of financial condition and results of operations are based on our condensed consolidated interim financial statements and related footnotes contained within this report. The process of preparing financial statements in conformity with GAAP requires the use of estimates and assumptions to determine certain of the assets, liabilities, revenue and expense. Our more critical accounting estimates used in the preparation of the consolidated financial statements were discussed in our 2014 Annual Report on Form 10-K. These critical estimates, for which no significant changes, other than those discussed in the results of operations, occurred during the nine months ended September 30, 2015, include estimates and assumptions for:



• oil and gas reserves		• asset retirement obligations
• full cost ceiling calculations		• stock-based compensation
• derivative instruments		• income taxes

These estimates and assumptions are based upon what we believe is the best information available at the time we make the estimate or assumption. The estimates and assumptions could change materially as conditions within and beyond our control change. Accordingly, actual results could differ materially from those estimates and assumptions.

OFF-BALANCE SHEET ARRANGEMENTS

We have no off-balance sheet arrangements within the meaning of Item 303(a)(4) of SEC Regulation S-K.

RECENTLY ISSUED ACCOUNTING STANDARDS

No other pronouncements materially affecting our financial statements have been issued since the filing of our 2014 Annual Report on Form 10-K.

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ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

We have established internal control policies and procedures for managing risk within our organization. The possibility of decreasing prices received for our natural gas, NGL and oil production is among the several risks that we face. We historically have sought to manage this risk by entering into derivative contracts. We have historically mitigated the downside risk of adverse price movements through the use of derivatives but, in doing so, we have also limited our ability to benefit from favorable price movements.

We have historically entered into financial derivative contracts to mitigate our exposure to commodity price risk associated with anticipated future production and to increase the predictability of our revenue. Utilization of our financial hedging program most often resulted in realized prices from the sale of our natural gas and NGLs that varied from market prices. As a result of settlements of derivative contracts, our revenue from natural gas and NGL production was greater by $25.1 million and $28.6 million for the 2015 period and 2014 period, respectively, and a net gain was recognized in net derivative gains (losses), net of $27.9 million for the 2015 period and a net loss of $15.1 million for the 2014 period.

In 2015, all of our derivatives were terminated either by us or the counterparties to such derivatives in anticipation or as a result of our Chapter 11 filings or through negotiations during the Chapter 11 proceedings. We no longer have any derivatives. The proceeds of the 2015 terminated derivatives were $138.9 million. We have used cash proceeds from these terminated derivatives to pay down amounts outstanding under our Combined Credit Agreements.

During the Chapter 11 proceedings, our ability to enter into new commodity derivatives covering additional estimated future production will be dependent upon either entering into unsecured hedges or obtaining Bankruptcy Court approval to enter into secured hedges. As a result, we may not be able to enter into additional commodity derivatives covering our production in future periods on favorable terms, or at all.

Interest Rate Risk

Changes in interest rates affect the interest rate we pay on borrowings under the Combined Credit Agreements.

At September 30, 2015, we did not have any availability under our Combined Credit Agreements as we were in default. If interest rates change by 1% on our September 30, 2015 variable debt balances of $157.0 million, our annual pre-tax income would decrease or increase by $1.6 million.

Adequate protection payments to the lenders under our Second Lien Term Loan and the holders of our Second Lien Notes are based in part on accrued and unpaid post-petition interest, which features a LIBOR floor. Consequently, a 1% increase in the applicable interest rates as of September 30, 2015, would increase our adequate protection payments by only 0.08% or an estimated annual adequate protection payment increase of $0.6 million.

Foreign Currency Risk

Our Canadian subsidiary uses the Canadian dollar as its functional currency. To the extent that business transactions in Canada are not denominated in Canadian dollars, we are exposed to foreign currency exchange rate risk. Non-functional currency transactions for the 2015 period and the 2014 period resulted in losses of $4.5 million and $2.0 million, respectively, and were included in other income.

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ITEM 4. Controls and Procedures

Conclusions Regarding the Effectiveness of Disclosure Controls and Procedures

We carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the period covered by this report pursuant to Securities Exchange Act Rule 13a-15. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were not effective to provide reasonable assurance that material information required to be disclosed by us (including our consolidated subsidiaries) in reports that we file or submit under the Securities Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. In light of the material weakness regarding our reserve report described below, we originally understated our impairment expense for oil and gas assets and have concluded that the financial statements as amended in this Form 10-Q/A present fairly, in all material respects, our consolidated financial condition, results of operation and cash flows in conformity with generally accepted accounting principles.

Changes in Internal Control Over Financial Reporting

Subsequent to the filing of our Quarterly Report on Form 10-Q as of September 30, 2015 on October 30, 2015, we determined that our estimate of proved oil and natural gas reserves for the period ended September 30, 2015 included an error in the calculation of our oil and natural gas proved reserve estimates for the period ended September 30, 2015. The reserve estimate error resulted in an understatement of impairment expense for the nine months ended September 30, 2015. The reserve estimate error was due to all applicable costs not being considered as our review control surrounding the inputs used in the estimate of our oil and natural gas proved reserves did not operate as designed and was not sufficient to identify certain costs inappropriately excluded from the analysis.

After fully evaluating the effect of the errors on our September 30, 2015 condensed consolidated financial statements, our management and the audit committee of our Board of Directors concluded that: (i) our September 30, 2015 condensed consolidated financial statements should be restated as presented in this Form 10-Q/A, (ii) a material weakness in internal controls over financial reporting existed as of September 30, 2015 because our review control over the inputs to the estimate of our oil and natural gas proved reserves did not operate as designed to identify costs inappropriately excluded from the analysis, resulting in a material misstatement of our financial statements, and (iii) our internal control over financial reporting was not effective as of September 30, 2015. In response to the identification of the material weakness, management has enhanced its process for determining and reviewing the inputs for our calculation of our oil and natural gas proved reserve estimates.

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PART II. OTHER INFORMATION

ITEM 1. Legal Proceedings

There have been no material changes in the legal proceedings described in Part I, Item 3 included in our 2014 Annual Report on Form 10-K.

ITEM 1A. Risk Factors

Other than risk associated with the nonpayment of amounts due pursuant to the gathering agreement with Fortune Creek, as described under "Contractual Obligations and Commercial Commitments" in Part 1, Item 2 of this Quarterly Report, there have been no material changes in the risk factors described in Part I, Item 1A included in our 2014 Annual Report on Form 10-K.

ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds

Issuer Purchases of Equity Securities

The following table summarizes our repurchases of Quicksilver common stock during the quarter ended September 30, 2015.



Period	Total Number of Shares Purchased ⁽¹⁾	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plan ⁽²⁾	Maximum Number of Shares that May Yet Be Purchased Under the Plan ⁽²⁾
July 2015	—	$	—	—	—
August 2015	—	$	—	—	—
September 2015	912	$	0.03	—	—
Total	912	$	0.03	—	—


⁽¹⁾	Represents shares of common stock surrendered by employees to satisfy income tax withholding obligations arising upon the vesting of restricted stock issued under our stock plan.


⁽²⁾	We do not have a publicly announced plan for repurchasing our common stock.

We have not paid cash dividends on our common stock and intend to retain our cash flows from operations for future operations and development of our business.

Furthermore, we are effectively restricted from making dividend payments during the pendency of the Chapter 11 proceedings.

ITEM 3. Defaults Upon Senior Securities

The U.S. Debtors’ Chapter 11 filings constituted an event of default under our Combined Credit Agreements, Second Lien Term Loan, Second Lien Notes, Senior Notes due 2019, Senior Notes due 2021 and Senior Subordinated Notes. We included a description of the defaults in our Current Report on Form 8‑K filed with the SEC on March 17, 2015.

ITEM 4. Mine Safety Disclosures

None.

ITEM 5. Other Information

None.

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ITEM 6.	Exhibits

Incorporated by Reference

Filed (†) or

Furnished (‡)

Herewith

(as indicated)

Exhibit

No.

Exhibit Description

Form

SEC

File No.

Exhibit

Filing

Date

10.1

Third Forbearance Agreement, dated September 15, 2015, among Quicksilver Resources Canada Inc. and the agents and lenders party thereto

8-K

001-14837

10.1

9/18/2015

31.1

Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

†

31.2

Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

†

32.1

Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

†

101.INS

XBRL Instance Document

‡

101.SCH

XBRL Taxonomy Extension Schema Linkbase Document

‡

101.CAL

XBRL Taxonomy Extension Calculation Linkbase Document

‡

101.LAB

XBRL Taxonomy Extension Labels Linkbase Document

‡

101.PRE

XBRL Taxonomy Extension Presentation Linkbase Document

‡

101.DEF

XBRL Taxonomy Extension Definition Linkbase Document

‡

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



Dated:	March 14, 2016	Quicksilver Resources Inc.

		By:	/s/ Vanessa Gomez LaGatta
			Vanessa Gomez LaGatta
			Senior Vice President-Chief Financial Officer and Treasurer (Duly Authorized Officer, Principal Financial Officer)

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EXHIBIT INDEX

Incorporated by Reference

Filed (†) or

Furnished (‡)

Herewith

(as indicated)

Exhibit

No.

Exhibit Description

Form

SEC

File No.

Exhibit

Filing

Date

10.1

Third Forbearance Agreement, dated September 15, 2015, among Quicksilver Resources Canada Inc. and the agents and lenders party thereto

8-K

001-14837

10.1

9/18/2015

31.1

Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

†

31.2

Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

†

32.1

Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

†

101.INS

XBRL Instance Document

‡

101.SCH

XBRL Taxonomy Extension Schema Linkbase Document

‡

101.CAL

XBRL Taxonomy Extension Calculation Linkbase Document

‡

101.LAB

XBRL Taxonomy Extension Labels Linkbase Document

‡

101.PRE

XBRL Taxonomy Extension Presentation Linkbase Document

‡

101.DEF

XBRL Taxonomy Extension Definition Linkbase Document

‡