UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934

POSTROCK ENERGY CORPORATION

Delaware		27-0981065
(State or other jurisdiction		(I.R.S. Employer
of incorporation or organization)		Identification No.)

210 Park Avenue, Suite 2750, Oklahoma City, OK 73102
(Address of principal executive offices) (Zip Code)

(405) 600-7704
(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 past 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 o

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

     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

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

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

     As of November 8, 2010, there were 8,238,982 shares of common stock of PostRock Energy Corporation outstanding.

 

 

POSTROCK ENERGY CORPORATION
FORM 10-Q
FOR THE QUARTER ENDED SEPTEMBER 30, 2010

TABLE OF CONTENTS

PART I — FINANCIAL INFORMATION
Item 1. Financial Statements
Condensed Consolidated Balance Sheets			F-1
Condensed Consolidated Statements of Operations			F-2
Condensed Consolidated Statements of Cash Flows			F-3
Condensed Consolidated Statement of Equity			F-4
Notes to Condensed Consolidated Financial Statements			F-5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			1
Item 3. Quantitative and Qualitative Disclosures About Market Risk			14
Item 4. Controls and Procedures			15
PART II — OTHER INFORMATION
Item 1. Legal Proceedings			18
Item 1A. Risk Factors			18
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			18
Item 3. Defaults Upon Senior Securities			18
Item 5. Other Information			19
Item 6. Exhibits			19
SIGNATURES			23
EX-10.9
EX-10.11
EX-10.13
EX-10.14
EX-31.1
EX-31.2
EX-32.1
EX-32.2

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements.

POSTROCK ENERGY CORPORATION AND SUBSIDIARIES

						(Predecessor)
		September 30, 2010				December 31, 2009
		(Unaudited)
ASSETS
Current assets
Cash and cash equivalents		$	1,262			$	20,884
Restricted cash			388				718
Accounts receivable — trade, net			9,320				13,707
Other receivables			858				2,269
Other current assets			2,193				8,141
Inventory			6,799				9,702
Current derivative financial instrument assets			36,103				10,624
Total current assets			56,923				66,045
Oil and gas properties under full cost method of accounting, net			49,233				40,478
Pipeline assets, net			141,503				136,017
Other property and equipment, net			17,859				19,433
Other assets, net			6,543				2,727
Long-term derivative financial instrument assets			47,255				18,955
Total assets		$	319,316			$	283,655
LIABILITIES AND EQUITY
Current liabilities
Accounts payable		$	8,675			$	10,852
Revenue payable			5,959				5,895
Accrued expenses			12,087				11,417
Current portion of notes payable			9,032				310,015
Current derivative financial instrument liabilities			2,525				1,447
Total current liabilities			38,278				339,626
Long-term derivative financial instrument liabilities			6,893				8,569
Other liabilities			6,989				6,552
Notes payable			239,763				19,295
Total liabilities			291,923				374,042
Commitments and contingencies
Series A Cumulative Redeemable Preferred Stock, $0.01 par value; issued and outstanding — 6,000 shares			49,217				—
Equity
Preferred stock of Predecessor, $0.001 par value; authorized shares — 50,000,000; none issued and outstanding							—
Common stock of Predecessor, $0.001 par value; authorized shares — 200,000,000; issued —32,160,121; outstanding —31,981,317							33
Preferred stock, $0.01 par value; authorized shares — 5,000,000; 190,476 Series B Voting Preferred Stock issued and outstanding			2
Common stock, $0.01 par value; authorized shares — 40,000,000; issued and outstanding —8,178,182			82
Additional paid-in capital			378,115				299,010
Treasury stock of Predecessor, at cost							(7	)
Accumulated deficit			(400,023	)			(447,413	)
Total stockholders’ deficit before non-controlling interests			(21,824	)			(148,377	)
Non-controlling interests							57,990
Total equity			(21,824	)			(90,387	)
Total liabilities and equity		$	319,316			$	283,655

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

POSTROCK ENERGY CORPORATION AND SUBSIDIARIES

						(Predecessor)								(Predecessor)
		Three Months				Three Months				March 6, 2010								Nine Months
		Ended				Ended				to								Ended
		September				September				September 30,				January 1, 2010				September
		30, 2010				30, 2009				2010				to March 5, 2010				30, 2009
Revenue
Oil and gas sales		$	21,484			$	18,329			$	50,075			$	18,659			$	56,711
Gas pipeline revenue			3,839				5,633				8,902				2,825				21,022
Total revenues			25,323				23,962				58,977				21,484				77,733
Costs and expenses
Oil and gas production			5,644				8,739				15,173				5,266				23,699
Pipeline operating			6,691				8,243				15,586				4,489				22,264
General and administrative			4,658				11,337				15,772				5,735				29,705
Depreciation, depletion and amortization			4,874				14,068				10,882				4,164				39,274
Impairment of oil and gas properties			—				—				—				—				102,902
Recovery of misappropropriated funds			(997	)			(9	)			(997	)			—				(3,406	)
Total costs and expenses			20,870				42,378				56,416				19,654				214,438
Operating income (loss)			4,453				(18,416	)			2,561				1,830				(136,705	)
Other income (expense)
Gain (loss) from derivative financial instruments			32,271				8,752				50,239				25,246				31,078
Other income (expense), net			67				(140	)			(163	)			(4	)			(1	)
Interest expense, net			(8,602	)			(6,920	)			(17,025	)			(5,336	)			(20,666	)
Total other income (expense)			23,736				1,692				33,051				19,906				10,411
Income (loss) before income taxes and non-controlling interests			28,189				(16,724	)			35,612				21,736				(126,294	)
Income tax expense			—				—				—				—				—
Net income (loss)			28,189				(16,724	)			35,612				21,736				(126,294	)
Net (income) loss attributable to non-controlling interest			—				5,197				—				(9,958	)			45,362
Net income (loss) attributable to controlling interest			28,189				(11,527	)			35,612				11,778				(80,932	)
Preferred stock dividends and accretion			209				—				209				—				—
Net income (loss) available to common stockholder		$	27,980			$	(11,527	)		$	35,403			$	11,778			$	(80,932	)
Net income (loss) per common share
Basic		$	3.47			$	(0.36	)		$	4.40			$	0.37			$	(2.54	)
Diluted		$	3.21			$	(0.36	)		$	4.22			$	0.36			$	(2.54	)
Weighted average shares outstanding
Basic			8,063				31,885				8,053				32,137				31,828
Diluted			8,719				31,885				8,381				32,614				31,828

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

POSTROCK ENERGY CORPORATION AND SUBSIDIARIES

						(Predecessor)
										Nine Months
										Ended
		March 6, 2010 to				January 1, 2010				September 30,
		September 30, 2010				to March 5, 2010				2009
Cash flows from operating activities
Net income (loss)		$	35,612			$	21,736			$	(126,294	)
Adjustments to reconcile net income (loss) to cash provided by operations
Depreciation, depletion and amortization			10,882				4,164				39,274
Stock-based compensation			987				808				1,143
Impairment of oil and gas properties			—				—				102,902
Amortization of deferred loan costs			5,339				2,094				4,109
Change in fair value of derivative financial instruments			(32,804	)			(21,573	)			52,018
Loss (gain) on disposal of property and equipment			131				—				83
Other non-cash changes to items affecting net income			111				—				(977	)
Change in assets and liabilities
Accounts receivable			4,624				(237	)			6,154
Other receivables			397				1,014				5,960
Other current assets			(501	)			466				1,215
Other assets			(6	)			2				153
Accounts payable			(2,942	)			(83	)			(20,221	)
Revenue payable			221				(157	)			(4,140	)
Accrued expenses			4,033				983				3,211
Other long-term liabilities			1				—				—
Other			—				—				(2	)
Cash flows from operating activities			26,085				9,217				64,588
Cash flows from investing activities
Restricted cash			331				(1	)			(143	)
Proceeds from sale of oil and gas properties			110				—				8,846
Equipment, development, leasehold and pipeline			(20,588	)			(2,282	)			(6,363	)
Cash flows from investing activities			(20,147	)			(2,283	)			2,340
Cash flows from financing activities
Proceeds from bank borrowings			2,100				900				2,930
Repayments of bank borrowings			(88,976	)			(41	)			(49,126	)
Proceeds from issuance of preferred stock and warrants			60,000				—				—
Refinancing and equity offering costs			(6,477	)			—				(569	)
Cash flows from financing activities			(33,353	)			859				(46,765	)
Net increase (decrease) in cash			(27,415	)			7,793				20,163
Cash and cash equivalents beginning of period			28,677				20,884				13,785
Cash and cash equivalents end of period		$	1,262			$	28,677			$	33,948

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

POSTROCK ENERGY CORPORATION

																														Total
																														Stockholders’
		Common								Preferred								Additional												Deficit Before
		Shares				Common				Shares				Preferred				Paid-in				Treasury				Accumulated				Non-controlling				Non-controlling				Total
		Issued				Stock				Issued				Stock				Capital				Stock				Deficit				Interests				Interests				Equity
Predecessor
Balance, December 31, 2009			32,160,121			$	33				—			$	—			$	299,010			$	(7	)		$	(447,413	)		$	(148,377	)		$	57,990			$	(90,387	)
Stock based compensation			(1,687	)			—				—				—				210				—				—				210				598				808
Net income							—				—				—				—				—				11,778				11,778				9,958				21,736
Balance, March 5, 2010			32,158,434			$	33				—			$	—			$	299,220			$	(7	)		$	(435,635	)		$	(136,389	)		$	68,546			$	(67,843	)
Balance, March 6, 2010			—			$	—				—			$	—			$	—			$	—			$	—			$	—			$	—			$	—
Issuance to Predecessor shareholders upon recombination			1,847,458				18				—				—				299,228				—				(435,635	)			(136,389	)			—				(136,389	)
Issuance to Predecessor noncontrolling interests upon recombination			6,191,516				62				—				—				68,484				—				—				68,546				—				68,546
Stock based compensation			139,208				2				—				—				985				—				—				987				—				987
Issuance of preferred stock and warrants, net			—				—				190,476				2				9,627				—				—				9,629				—				9,629
Preferred stock dividends			—				—				—				—				(180	)			—				—				(180	)			—				(180	)
Preferred stock accretion			—				—				—				—				(29	)			—				—				(29	)			—				(29	)
Net income			—				—				—				—				—				—				35,612				35,612				—				35,612
Balance, September 30, 2010			8,178,182			$	82				190,476			$	2			$	378,115			$	—			$	(400,023	)		$	(21,824	)		$	—			$	(21,824	)

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

POSTROCK ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 2010
(Unaudited)

Note 1 — Basis of Presentation

     PostRock Energy Corporation (“PostRock”) is a Delaware corporation formed on July 1, 2009 for the purpose of effecting the recombination of Quest Resource Corporation (“QRCP”), Quest Energy Partners, L.P. (“QELP”) and Quest Midstream Partners, L.P. (“QMLP”). On July 2, 2009, PostRock, QRCP, QELP, QMLP and other parties thereto entered into a merger agreement pursuant to which QRCP, QELP and QMLP would recombine. The recombination was effected by forming a new publicly traded corporation, subsequently named PostRock, that, through a series of mergers and entity conversions, wholly owns all three entities. The recombination was completed on March 5, 2010. Since QRCP was the parent company which consolidated both QELP and QMLP prior to the recombination, the recombination was a transaction between equity interest holders within a consolidated entity rather than a business combination. The transaction was therefore accounted for on a historical cost basis. Since PostRock did not own any assets prior to the consummation of the recombination, the purpose of these condensed consolidated financial statements is to present the historical consolidated financial position and results of operations, cash flows and changes in equity of the predecessor entities (collectively referred to as “Predecessor”) prior to the recombination and to present such information for PostRock subsequent to the recombination. Unless the context requires otherwise, references to “we,” “us,” “our” or the “Company” are intended to mean and include the consolidated businesses and operations of our Predecessor for dates prior to March 6, 2010 and to the consolidated businesses and operations of PostRock and its subsidiaries for dates on or subsequent to March 6, 2010.

     The Company is an independent energy company involved in the acquisition, development, gathering, transportation, exploration, and production of oil and natural gas. Its principal operations and producing properties are located in the Cherokee Basin of southeastern Kansas and northeastern Oklahoma. The Cherokee Basin operations are currently focused on developing and gathering coal bed methane (“CBM”) gas production. The Company also owns and operates an interstate natural gas transmission pipeline.

     The Company also has development, exploration, production and gathering assets in the Appalachian Basin in West Virginia and New York. The Company’s Appalachian Basin operations are primarily focused in the Marcellus Shale. An investment advisory company has been engaged to pursue strategic alternatives, which may include a sale, of some of the Company’s Appalachian assets.

     The condensed consolidated balance sheet as of December 31, 2009, which has been derived from audited financial statements, and the unaudited interim condensed consolidated financial statements have been prepared by PostRock and the Predecessor pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) and reflect all adjustments that are, in the opinion of management, necessary for a fair statement of the results for the interim periods on a basis consistent with the annual audited consolidated financial statements. All such adjustments are of a normal recurring nature. Certain information, accounting policies and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been omitted pursuant to such rules and regulations, although the Company believes that the disclosures are adequate to make the information presented not misleading. These condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and the summary of significant accounting policies and notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2009 (the “2009 Form 10-K”).

     The preparation of condensed consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The operating results for the interim periods are not necessarily indicative of the results to be expected for the full year.

Equity and Debt Restructuring

     On September 21, 2010, the Company completed a $60 million equity investment by White Deer Energy L.P. (“White Deer”) and a restructuring of the Company’s existing credit agreements. These transactions resulted in more favorable terms for its credit agreements and a $58.9 million repayment of outstanding debt. See Notes 2 and 3 for further details on the restructuring of the Company’s credit facilities and the White Deer investment.

     Prior to the equity investment and debt restructuring transactions described above, it was uncertain whether the Company would be able to meet its debt obligations as they came due. With the closing of the equity investment and the restructuring of the credit agreements, the Company has alleviated uncertainty regarding its ability to fund payment obligations in the near term.

Recent Accounting Pronouncements and Recently Adopted Accounting Pronouncements

     In January 2010, the Financial Accounting Standards Board (“FASB”) released Accounting Standards Update (“ASU”) 2010-06, Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements. The update requires reporting entities to provide information about movements of assets among Levels 1 and 2 of the three-tier fair value hierarchy established under FASB Accounting Standards Codification (“FASB ASC”) 820. The update also requires separate presentation (on a gross basis rather than as one net number) about purchases, sales, issuances, and settlements within the reconciliation of activity in Level 3 fair value measurements. The guidance is effective for any fiscal period beginning after December 15, 2009 except for the requirement to separately disclose purchases, sales, issuances, and settlements, which will be effective for any fiscal period beginning after December 15, 2010. The Company adopted the provisions of this update relating to disclosure on movement of assets among Levels 1 and 2 beginning with the quarter ended March 31, 2010. Other than additional disclosure required by the update, there was no material impact on its financial statements.

     In February 2010, the FASB released ASU 2010-09, Subsequent Events (Topic 855): Amendments to Certain Recognition and Disclosure Requirements which removed some contradictions between the requirements of GAAP and the SEC’s filing rules. As a result, public companies will no longer have to disclose the date of their financial statements in both issued and revised financial statements. The amendments became effective upon issuance of the update and the Company adopted the provisions of this update beginning with the quarter ended March 31, 2010 with no material impact on its financial statements.

Note 2 — Long-Term Debt

Former Credit Agreements

     On September 21, 2010, the Company completed a restructuring of its credit agreements. Prior to the restructuring, the Company had four credit agreements (the “Former Credit Agreements”) summarized as follows:

     (i) A term loan with an outstanding principal balance of approximately $125 million and no available capacity, secured by the Company’s assets owned by Quest Cherokee, LLC (the “Quest Cherokee Loan”);

     (ii) A second lien senior term loan with an outstanding principal balance of approximately $30.2 million, secured by a second lien on the Company’s assets owned by Quest Cherokee, LLC (the “Second Lien Loan”);

     (iii) A credit agreement with an outstanding principal balance of approximately $118.7 million secured by the Company’s assets owned by PostRock Midstream LLC and Bluestem Pipeline, LLC, which included the Bluestem gas gathering system and the KPC Pipeline (the “Midstream Loan”); and

     (iv) A credit agreement with an outstanding principal balance of approximately $43.8 million, secured by the Company’s Appalachian assets owned indirectly by PostRock Energy Services Corporation (the “PESC Loan”).

     The terms of the Company’s previous credit facilities and activity prior to the restructuring are described in Item 8. Financial Statement and Supplementary Data in the 2009 Form 10-K and in Part I, Item 1. of the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010.

New Credit Agreements

     As of September 30, 2010, the Company has three credit agreements (the “New Credit Agreements”) summarized as follows:

     (i) A $350 million secured borrowing base revolving credit facility with an initial borrowing base of $225 million and outstanding borrowings of $190.0 million secured by, among other things, a first lien on the Company’s Cherokee Basin exploration and production assets, certain producing Appalachian production assets and the Cherokee Basin gas gathering system and a second lien on the Company’s interstate natural gas transportation pipeline (the “Borrowing Base Facility”);

     (ii) A term loan with an outstanding principal balance of $15 million, secured by, among other things, a first lien on the Company’s interstate natural gas transportation pipeline and a second lien on the Company’s Cherokee Basin exploration and production assets, certain producing Appalachian production assets and the Cherokee Basin gas gathering system (the “Secured Pipeline Loan”); and

     (iii) A term loan with an outstanding principal balance of $43.8 million, secured by the Company’s assets owned by Quest Eastern Resource LLC (“QER”), which include certain producing and non-producing Appalachian properties and the Appalachian gas gathering system, and a pledge of the equity of QER (the “QER Loan”).

The following is a summary of long-term debt as of the dates indicated (in thousands):

						(Predecessor)
		September 30,				December 31,
		2010				2009
New Credit Agreements
Borrowing Base Facility		$	190,000			$	—
Secured Pipeline Loan			15,000				—
QER Loan			43,760				—
Former Credit Agreements
Quest Cherokee Loan			—				145,000
Second Lien Loan			—				29,821
Midstream Loan			—				118,728
PESC Loan			—				35,658
Notes payable to banks and finance companies			35				103
Total debt			248,795				329,310
Less current maturities included in current liabilities			9,032				310,015
Total long-term debt		$	239,763			$	19,295

Borrowing Base Facility

     The Borrowing Base Facility with PostRock Energy Services Corporation (“PESC”) and PostRock MidContinent Production, LLC (formerly known as Bluestem Pipeline, LLC and the successor by merger to Quest Cherokee, LLC) (“MidContinent”) as borrowers, Royal Bank of Canada (“RBC”) as administrative and collateral agent, and the lenders party thereto is a secured borrowing base facility with an initial borrowing base of $225 million and is guaranteed by PostRock and certain of its subsidiaries.

     The Borrowing Base Facility is the result of restructuring the Quest Cherokee Loan, the Second Lien Loan and all but $15 million of the outstanding indebtedness under the Midstream Loan (see “ — Secured Pipeline Loan” below) and amending and restating the related agreements in whole or in part.

     Under the terms of the Borrowing Base Facility, MidContinent and PESC prepaid the outstanding indebtedness under the Quest Cherokee Loan in an amount equal to approximately $19.2 million. In consideration therefor, the lenders completely restructured the credit agreements relating to the Quest Cherokee Loan and the Second Lien Loan with the Borrowing Base Facility, partially restructured the Midstream Loan, and secured the Borrowing Base Facility with the same assets that secured the Quest Cherokee Credit Agreement and the Second Lien Loan Agreement (including the assets of MidContinent, which include all of the oil and gas exploration assets located in

the Cherokee Basin and all of the oil and gas exploration assets located in the Appalachian basin that are not owned by QER) in addition to the Bluestem gas gathering system (which had formerly partially secured the Midstream Loan).

     Other material terms of the Borrowing Base Facility include the following:

Covenants The Borrowing Base Facility contains affirmative and negative covenants that are customary for transactions of this type, including financial covenants that prohibit PESC, MidContinent and any of their subsidiaries (with certain exceptions) from:

• permitting the borrowers’ current ratio (ratio of consolidated current assets (as defined in the agreement) to consolidated current liabilities (as defined in the agreement)) at any fiscal quarter-end to be less than or equal to 1.0 to 1.0;

• permitting the borrowers’ interest coverage ratio (ratio of adjusted consolidated EBITDA to consolidated interest charges) at any fiscal quarter-end to be less than or equal to 3.0 to 1.0 measured on a trailing four quarter basis; and

• permitting the borrowers’ leverage ratio (ratio of cash adjusted consolidated funded debt to adjusted consolidated EBITDA for the four fiscal quarters ending on the applicable fiscal quarter-end) (1) commencing with the quarter ending September 30, 2010, and ending on the quarter ending March 31, 2011, to be greater than or equal to 4.5 to 1.0, (2) commencing with the quarter ending June 30, 2011, and ending on the quarter ending March 31, 2012, to be greater than or equal to 4.0 to 1.0, and (3) commencing with the quarter ending June 30, 2012, and continuing until the maturity date to be greater than or equal to 3.5 to 1.0.

Interest Rate LIBOR plus 3.50% to 4.00% or, at the borrowers option, Base Rate plus 2.50% to 3.00%, in each case depending on utilization. The interest rate on the outstanding borrowings at September 30, 2010, was 4.01%.

Maturity Date June 30, 2013.

Capital Expenditures The borrowers are obligated to make minimum capital expenditures in the cumulative aggregate amount of (1) $5.0 million for the six-month period ending December 31, 2010, (2) $10.0 million for the nine-month period ending March 31, 2011, (3) $17.5 million for the 12-month period ending June 30, 2011, and (4) $25.0 million for the 15-month period ending September 30, 2011. If the borrowers have not expended the required amounts by December 31, 2010, the borrowers are entitled to an additional quarter to expend that amount. In the event the borrowers have not expended the minimum aggregate capital expenditure amount required to be expended by March 31, 2011, June 30, 2011 or September 30, 2011, the borrowing base will be reduced by an amount equal to the shortfall.

Borrowing Base Redetermination The first borrowing base redetermination with respect to the indebtedness under the Borrowing Base Facility will be effective on July 31, 2011 and based on the Company’s March 31, 2011 oil and natural gas reserves. After July 31, 2011, the borrowing base redeterminations by the lenders will be effective every April 30th and October 31st until maturity taking into account the value of MidContinent’s proved reserves. In addition, the borrowers, during each period between scheduled redeterminations of the borrowing base, and, the required lenders, after the redetermination effective April 30, 2012, have the right to initiate a redetermination of the borrowing base between each scheduled redetermination, provided that no more than two such redeterminations may occur in a 12-month period. In addition, upon a material disposition of assets and a material acquisition of oil and gas properties, and in certain other limited circumstances, the borrowing base will or may be redetermined. If the borrowing base is reduced in connection with a redetermination, the borrowers can elect to either repay the entire deficiency within 30 days, repay the deficiency in six equal monthly installments, or contribute additional properties to increase the value of the collateral to support the prior borrowing base.

Payments Principal is required to be repaid on the maturity date. The borrowers are required to make a mandatory prepayment of principal upon the occurrence of any of the following events: (a) a material disposition of assets; (b) a sale of the Appalachian assets owned by MidContinent; (c) a change of control occurring after September 21, 2010; and (d) the existence of a borrowing base deficiency. Interest payments are due (i) at the end of each LIBOR interest period but in no event less frequently than quarterly in the case of LIBOR loans or (ii) quarterly in the case of Base Rate loans.

Security Interest The Borrowing Base Facility is secured by (i) a first lien on all of PostRock’s assets except for the Appalachian properties owned by QER, the equity of QER, three lateral gas pipelines owned by Quest Transmission Company, LLC, the KPC Pipeline and the other assets of KPC and (ii) a second lien on the KPC Pipeline and the other assets of KPC.

Events of Default Events of default are customary for transactions of this type and include, without limitation, non-payment of principal when due, non-payment of interest, fees and other amounts within three business days after the due date, failure to perform or observe covenants and agreements (subject to a 30-day cure period in certain cases), representations and warranties not being correct in any material respect when made, certain acts of bankruptcy or insolvency, cross defaults to other material indebtedness, non-appealable judgment in a material amount is entered against a borrower or its affiliate, ERISA violations, invalidity of loan documents, dissolution, collateral impairment, borrowing base deficiencies, and change of control.

Secured Pipeline Loan

     The Secured Pipeline Loan with PESC and PostRock KPC Pipeline, LLC (“KPC”) as borrowers, RBC as administrative and collateral agent, and the lenders party thereto is a $15 million term loan secured by a first lien on the KPC Pipeline and the other assets of KPC, and by a second lien on the assets on which the lenders under the Borrowing Base Facility have a first lien.

     Under the terms of the Secured Pipeline Loan, PESC and KPC prepaid approximately $14,700,000 of the outstanding indebtedness under the Midstream Loan in exchange for the assignment by the lenders under the Midstream Loan of approximately $89,000,000 of the indebtedness owing under the Midstream Loan to the lenders under the Borrowing Base Facility. The remaining $15,000,000 of such indebtedness was retained under the Secured Pipeline Loan.

Other material terms of the Secured Pipeline Loan include the following:

Covenants The Secured Pipeline Loan contains affirmative and negative covenants that are customary for credit agreements of this type. The financial covenants in the Secured Pipeline Loan are substantially the same as the financial covenants in the Borrowing Base Facility.

Interest Rate LIBOR plus 3.75% or, at the borrowers option, Base Rate plus 2.75%. The interest rate on September 30, 2010, was 4.01%.

Maturity Date February 28, 2012.

Payments Principal payments in the amount of $500,000 are due monthly for the first six months beginning October 21, 2010, and $1,000,000 monthly thereafter, as well as monthly interest payments. Prepayments are required to be made in the following amounts: (a) net available cash from the sale of the KPC Pipeline or the equity of KPC and (b) total outstanding amounts upon a change of control.

Events of Default Events of default under the Secured Pipeline Loan are customary for transactions of this type and include, without limitation, non-payment of principal when due, non-payment of interest, fees and other amounts within three business days after the due date, failure to perform or observe covenants and agreements (subject to a 30-day cure period in certain cases), representations and warranties not being correct in any material respect when made, certain acts of bankruptcy or insolvency, cross defaults to other material indebtedness, non-

appealable judgment in a material amount is entered against a borrower or its affiliate, ERISA violations, invalidity of loan documents, dissolution, collateral impairment, and change of control.

QER Loan

     As part of the closing of our amended and restated credit facilities, PESC, QER and RBC entered into an assumption agreement whereby QER assumed all of PESC’s rights and obligations as borrower under the PESC Loan. In addition, QER, as borrower, entered into the third amended and restated credit agreement with RBC in the amount of approximately $43.8 million. In connection therewith, RBC, the lender under the PESC Loan released PESC from any liability or obligation to repay amounts owing under the PESC Loan and all of the guarantors thereunder from their respective guarantees of the indebtedness owing under the PESC Loan and (except for QER) from their respective mortgages and security agreements. RBC also released the liens on all the collateral owned by PESC, other than the Appalachian assets owned by QER and the equity of QER; and agreed to reconvey the overriding royalty interests to their respective grantors (or their designees) at such time as the Appalachian assets or equity of QER are sold. Accordingly, under the QER Loan, RBC has recourse only to QER, its assets and the equity of QER.

Other material terms of the QER Loan include the following:

Covenants The QER Loan contains non-financial affirmative and negative covenants that are customary for credit agreements of this type. There are no financial covenants contained in the QER Loan.

Interest Rate LIBOR plus 4.00% or, at the borrowers option, Base Rate plus 3.00%. The weighted average interest rate on September 30, 2010, was 4.27%.

Maturity Date June 30, 2013.

Payments No interim principal payments are scheduled under the QER Loan. Interest payments are not required until on or after March 31, 2011, and then are due quarterly, in the case of Base Rate Loans, or at the end of each LIBOR interest period, but in no event less frequently than quarterly, in the case of LIBOR loans. Mandatory prepayment of the net cash proceeds upon a disposition of the Appalachian assets owned by QER is required. The principal plus accrued interest is due at maturity.

Security Interest The QER Loan is secured by a first priority lien on the assets of QER and a pledge by PESC of QER’s equity.

Events of Default Events of default are customary for transactions of this type and include, without limitation, non-payment of principal when due, non-payment of interest, fees and other amounts within three business days after the due date, failure to perform or observe covenants and agreements (subject to a 30-day cure period in certain cases), representations and warranties not being correct in any material respect when made, certain acts of bankruptcy or insolvency, non-appealable judgment in a material amount is entered against a borrower or its affiliate, ERISA violations, invalidity of loan documents, dissolution, collateral impairment, and change of control.

     In connection with the QER Loan, PostRock entered into an asset sale agreement with RBC that allows PostRock to sell QER or substantially all of its assets and, in the event the proceeds are not adequate to repay the QER Loan in full, PostRock has agreed to pay a portion of such shortfall in cash, stock or a combination thereof.

     Troubled debt restructuring — The interest rate margin under the QER Loan of 3%-4% is lower than the margin under the previous PESC Loan, which was 10%. Due to a reduction in the interest rate coupled by the Company’s recent financial difficulties, the QER Loan restructuring met the criteria under FASB ASC 470-60 Debt—Troubled Debt Restructurings by Debtors (“FASB ASC 470-60”) to be classified as a troubled debt restructuring. In accordance with accounting guidance, the Company evaluated whether the sum of future cash flows under the QER Loan would be less than the amount payable under the original loan (PESC Loan), which would require a gain to be recognized on the debt restructuring. These cash flows are indeterminate as they depend on proceeds from the sale

of QER’s assets. Since such proceeds could potentially be sufficient to repay the QER Loan in full, the Company determined that it was not necessary to recognize a gain on the debt restructuring. As required by FASB ASC 470-60, the Company expensed $0.9 million in fees incurred to restructure the debt which are reflected in interest expense, net, on the condensed consolidated statements of operations. The Company evaluated the restructuring of its former credit facilities that resulted in the Borrowing Base Facility and Secured Pipeline Loan and determined that they were not troubled debt restructurings.

Debt fees

     Upon the successful restructuring of the Company’s Former Credit Agreements, the unamortized balance of debt fees related to those agreements was $1.8 million. The Company wrote off the unamortized balance of $1.8 million in accordance with the provisions of FASB ASC 470-50 Debt—Modifications and Extinguishments.

     The Company incurred a total of $6.8 million in fees related to its New Credit Facilities and the White Deer equity investment of which $4.4 million related to the Borrowing Base Facility and $0.3 million related to the Secured Pipeline Loan were capitalized, $0.9 million related to the QER Loan was recorded as an expense, and the remaining $1.2 million related to the White Deer equity investment was recorded as a reduction to additional paid-in capital. The write-off of unamortized debt fees and the fees related to the QER Loan have been recognized as a component of interest expense, net, on the condensed consolidated statements of operations.

Note 3 — Redeemable Preferred Stock and Noncontrolling Interests

     Noncontrolling interests — A rollforward of the noncontrolling interests of the Predecessor’s investments in QELP and QMLP for the periods indicated is as follows (in thousands):

		(Predecessor)
						Three Months				Nine Months
		January 1, 2010				Ended September				Ended September
		to March 5, 2010 (1)				30, 2009				30, 2009
QELP
Beginning of period		$	15,350			$	16,131			$	58,666
Net income (loss) attributable to non-controlling interest			10,365				(4,418	)			(46,986	)
Stock compensation expense related to QELP unit-based awards			167				17				50
End of period		$	25,882			$	11,730			$	11,730
QMLP
Beginning of period		$	42,640			$	148,611			$	145,870
Net income (loss) attributable to non-controlling interest			(407	)			(779	)			1,624
Stock compensation expense related to QMLP unit-based awards			431				204				542
End of period		$	42,664			$	148,036			$	148,036
Total non-controlling interest at end of period		$	68,546			$	159,766			$	159,766

     Redeemable Preferred Shares — On September 21, 2010, the Company issued to White Deer 6,000 shares of the Company’s Series A Cumulative Redeemable Preferred Stock (the “Series A Preferred Stock”), 190,476.19 shares of its Series B Voting Preferred Stock (the “Series B Preferred Stock”) and warrants to purchase 19,047,619 shares of the Company’s common stock. The preferred stock and warrants were issued in exchange for a $60 million equity infusion from White Deer.

     The Series A Preferred Stock is entitled to a cumulative dividend of 12% per year on its liquidation preference, compounded quarterly. The liquidation preference totaled $60 million on the closing date of the equity investment and will increase by the amount of accrued and unpaid dividends. The Company is not required to pay cash

dividends until July 1, 2013. Any dividends prior to that time not paid in cash will accrue as additional liquidation preference. Subsequent to July 13, 2013, dividends are required to be paid in cash and any payment default after that date will increase the accrual of the additional liquidation preference during the default period from a rate of 12% to 14%. The Company is required to redeem the Series A Preferred Stock on March 21, 2018 at 100% of the liquidation preference. From and after one year from the issuance date until such mandatory redemption date, the Company will have the option to redeem all or a specified minimum portion of the Series A Preferred Stock at 110% of the liquidation preference. The holders of the Series A Preferred Stock have the right to require the Company to purchase their shares on the occurrence of specified change in control events at 110% of the liquidation preference. In the case of specified defaults by the Company, including the failure to pay dividends for any quarterly period after July 1, 2013, and until the defaults are cured, the holders of the Series A Preferred Stock have the right to appoint two additional directors to the Board of Directors. The Series A Preferred Stock do not vote generally with the common stock, but have specified approval rights with respect to, among other things, changes to the Company’s certificate of incorporation that affect the Series A Preferred Stock, cash dividends on the common stock or other junior stock, redemptions or repurchases of common stock or other capital stock, increases in the size of the Board of Directors, changes to specified debt agreements and changes to the Company’s business.

     The warrants issued at the closing of the investment are exercisable for a total of 19,047,619 shares of common stock at an exercise price of $3.15 per share which represents an approximate 5% premium to the closing price of the common stock on September 1, 2010, the day before the transaction was publicly announced. Prior to July 1, 2013, the Company may elect to pay dividends on the Series A Preferred Stock in cash. During this period, if such dividends are not paid in cash on a dividend payment date, the Company will issue additional warrants exercisable for a number of shares of common stock equal to the amount of dividends that are not paid on that dividend payment date divided by the closing price of the common stock on the trading date immediately preceding the dividend payment date. The exercise price of the warrants will be such closing price. The warrants, including any additional warrants, are exercisable for 90 months following the applicable issuance date, but not before the earlier of January 19, 2011 or a change in control of the Company. Each warrant is coupled, and may only be transferred as a unit, with a number of one one-hundredths of a share, or a “fractional share,” of Series B Preferred Stock equal to the number of shares of common stock purchasable upon exercise of the warrant. The warrants and the Series B Preferred Stock may not be transferred separately. If and when the warrant is exercised, the holder of the warrant will be required to deliver to the Company, as part of the payment of the exercise price, a number of fractional shares of Series B Preferred Stock equal to the number of shares of common stock purchased upon such exercise. The holders of the warrants have the right to pay the exercise price in cash, by electing a cashless exercise (whereby the holder will receive the excess of the market price of the common stock over the exercise price in shares of common stock valued at the market price) or by tendering shares of Series A Preferred Stock with a liquidation preference equal to the exercise price. If the market price of the common stock exceeds 300% of the exercise price for a specified period of time and other conditions are satisfied, the Company may require the holders of the warrants to exercise warrants to purchase up to 50% of shares covered thereby, but in the aggregate not less than 750,000 shares or more than 50% of the trading volume of the common stock over the preceding 20 trading days.

     The holders of Series B Preferred Stock are entitled to vote in the election of directors and on all other matters submitted to a vote of the holders of common stock of the Company, with the holders of Series B Preferred Stock and the holders of common stock voting together as a single class. Each fractional share of Series B Preferred Stock has one vote. The voting rights of each share of Series B Preferred Stock may not be exercised by any person other than the holder of the warrant that is part of the unit with such share or fractional share and will expire on the expiration date of such warrant. The Series B Preferred Stock has no dividend rights and a nominal liquidation preference. Until December 31, 2011, the holders of the Series B Preferred Stock and their affiliates are limited to 45% of the votes applicable to all outstanding voting stock, which limit includes any common stock held by them. After December 31, 2011, the limit only restricts the voting of the Series B Preferred Stock, and the holders and their affiliates may vote any shares of common stock held by them without regard to that limit.

     The Series A Preferred Stock has been recorded outside of permanent equity and liabilities, in the Company’s condensed consolidated balance sheet because the settlement provisions of the warrants allow White Deer to “net exercise” the warrants by requiring the Company to repay the Series A Preferred Stock at the liquidation preference to offset the strike price of the warrants that would otherwise be due from White Deer in cash. Absent this provision, the Series A Preferred Stock would have met the definition of mandatorily redeemable preferred stock under FASB ASC 480 Distinguishing Liabilities from Equity (“FASB ASC 480”) which would have required recognition as a

liability. This provision allows the Series A Preferred Stock to effectively be convertible to common stock at the election of White Deer. In the event that White Deer exercises the warrants without net-exercising the Series A Preferred Stock back to the Company as payment for the strike price of the warrants, the Company will be required to reclassify a proportionate amount of Series A Preferred Stock from temporary equity to liabilities as that portion of the Series A Preferred Stock is no longer convertible to common stock.

     The $60 million in gross proceeds from White Deer was allocated among the Series A Preferred Stock, Series B Preferred Stock and the warrants. The warrants were recognized at a fair value of $10.8 million on the date of issuance and recorded as additional paid in capital in our condensed consolidated balance sheet. The preferred stock was subsequently recognized in an amount equal to the $60 million in proceeds net of the fair value of the warrants resulting in $49.2 million recorded in temporary equity related to the Series A Preferred Stock and approximately $2,000 recorded in equity related to the par value of the Series B Preferred Stock. As the Series A Preferred Stock is initially recorded at a discount, it will be accreted to its full redemption value over the 7 ¹/2 year term under the interest method in accordance with FASB ASC 480. Offering fees of $1.2 million were recorded as a reduction of additional paid in capital.

     The Company used a Monte Carlo stock option pricing simulation to value the warrants. The warrants are classified as Level 3 within the fair value hierarchy established by FASB ASC 820 because observable market data is not available. The assumptions used in the model for the warrant valuation included the exercise price of $3.15 per share and inputs relating to stock price drift and daily volatility. The Series A Preferred Stock also contains a put option whereby White Deer can put the stock to the Company at 110% of the liquidation preference upon a change in control. Under FASB ASC 815, “Derivatives and Hedging,” (“FASB ASC 815”) it was determined that the put option is both indexed to the Company’s own stock and classified in stockholder’s equity as the underlying Series A Preferred Stock is classified as temporary equity. Accordingly, the put option is scoped out of FASB ASC 815 and does not require separate accounting as a bifurcated derivative.

     The following table describes the changes in temporary equity currently comprised of the Series A Preferred Stock (in thousands except share amounts):

		Series A Preferred				Series A Preferred
		Stock				Shares
Balance on September 21, 2010		$	—				—
Issuance of Series A Preferred Stock			49,188				6,000
Accretion			29				—
Balance on September 30, 2010		$	49,217				6,000

Note 4 — Derivative Financial Instruments

     The Company is exposed to commodity price risk and management believes it prudent to periodically reduce exposure to cash-flow variability resulting from this volatility. Accordingly, the Company enters into certain derivative financial instruments in order to manage exposure to commodity price risk inherent in its oil and gas production operations. Specifically, the Company may utilize futures, swaps and options. Futures contracts and commodity swap agreements are used to fix the price of expected future oil and gas sales at major industry trading locations, such as Henry Hub, Louisiana for gas and Cushing, Oklahoma for oil. Basis swaps are used to fix or float the price differential between the price of gas at Henry Hub and various other market locations. Options are used to fix a floor and a ceiling price (collar) for expected future oil and gas sales. Derivative financial instruments are also used to manage commodity price risk inherent in customer pricing requirements and to fix margins on the future sale of natural gas.

     Settlements of any exchange-traded contracts are guaranteed by the New York Mercantile Exchange (NYMEX) or the Intercontinental Exchange and are subject to nominal credit risk. Over-the-counter traded swaps, options and physical delivery contracts expose us to credit risk to the extent the counterparty is unable to satisfy its settlement commitment. The Company monitors the creditworthiness of each counterparty and assesses the impact, if any, on fair value. In addition, it routinely exercises its contractual right to net realized gains against realized losses when settling with our swap and option counterparties.

     The Company accounts for its derivative financial instruments in accordance with FASB ASC 815 Derivatives and Hedging (“FASB ASC 815”). FASB ASC 815 requires that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. FASB ASC 815 requires that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met or exemptions for normal purchases and normal sales (“NPNS”) as permitted by FASB ASC 815 exist. The Company does not designate its derivative financial instruments as hedging instruments for financial accounting purposes and, as a result, it recognizes the change in the respective instruments’ fair value currently in earnings. In accordance with FASB ASC 815, the table below outlines the classification of derivative financial instruments on the condensed consolidated balance sheet and their financial impact in the condensed consolidated statements of operations as of and for the periods indicated (in thousands):

Fair Value of Derivative Financial Instruments

								(Predecessor)
				September 30,				December 31,
Derivative Financial Instruments		Balance Sheet location		2010				2009
Commodity contracts		Current derivative financial instrument asset		$	36,103			$	10,624
Commodity contracts		Long-term derivative financial instrument asset			47,255				18,955
Commodity contracts		Current derivative financial instrument liability			(2,525	)			(1,447	)
Commodity contracts		Long-term derivative financial instrument liability			(6,893	)			(8,569	)
				$	73,940			$	19,563

     Settlements in the normal course of maturities of derivative financial instrument contracts result in cash receipts from or cash disbursement to derivative contract counterparties and are, therefore, realized gains or losses. Changes in the fair value of derivative financial instrument contracts are included in income currently with a corresponding increase or decrease in the balance sheet fair value amounts. Gains and losses associated with derivative financial instruments related to oil and gas production were as follows for the periods indicated (in thousands):

														(Predecessor)
		Three Months				Three Months				March 6, 2010				January 1,				Nine Months
		Ended September				Ended September				to September 30,				2010 to March				Ended September
		30, 2010				30, 2009				2010				5, 2010				30, 2009
Realized gains (losses)		$	6,826			$	19,616			$	17,435			$	3,673			$	83,096
Unrealized gains (losses)			25,445				(10,864	)			32,804				21,573				(52,018	)
Total		$	32,271			$	8,752			$	50,239			$	25,246			$	31,078

The following table summarizes the estimated volumes, fixed prices and fair values attributable to oil and gas derivative contracts as of September 30, 2010:

		Remainder of				Year Ending December 31,
		2010				2011				2012				2013				Total
Natural Gas Swaps
Contract volumes (Mmbtu)			4,098,589				13,550,302				11,000,004				9,000,003				37,648,898
Weighted-average fixed price per Mmbtu		$	6.30			$	6.80			$	7.13			$	7.28			$	6.96
Fair value, net		$	10,497			$	33,215			$	22,607			$	16,992			$	83,311
Basis Swaps
Contract volumes (Mmbtu)			948,141				8,549,998				9,000,000				9,000,003				27,498,142
Weighted-average fixed price per Mmbtu		$	(0.69	)		$	(0.67	)		$	(0.70	)		$	(0.71	)		$	(0.69	)
Fair value, net		$	(396	)		$	(2,857	)		$	(3,146	)		$	(3,019	)		$	(9,418	)
Crude Oil Swaps
Contract volumes (Bbl)			7,500				—				—				—				7,500
Weighted-average fixed price per Bbl		$	87.50			$	—			$	—			$	—			$	87.50
Fair value, net		$	47			$	—			$	—			$	—			$	47
Total fair value, net		$	10,148			$	30,358			$	19,461			$	13,973			$	73,940

The following table summarizes the estimated volumes, fixed prices and fair values attributable to gas derivative contracts of the Company’s predecessor as of December 31, 2009:

		Year Ending December 31,
		2010				2011				2012				Thereafter				Total
		(in thousands, except volumes and per unit data)
Natural Gas Swaps
Contract volumes (Mmbtu)			16,129,060				13,550,302				11,000,004				9,000,003				49,679,369
Weighted-average fixed price per Mmbtu		$	6.26			$	6.80			$	7.13			$	7.28			$	6.78
Fair value, net		$	10,424			$	7,530			$	6,662			$	4,763			$	29,379
Natural Gas Basis Swaps
Contract volumes (Mmbtu):			3,630,000				8,549,998				9,000,000				9,000,003				30,180,001
Weighted-average fixed price per Mmbtu		$	(0.63	)		$	(0.67	)		$	(0.70	)		$	(0.71	)		$	(0.69	)
Fair value, net		$	(1,402	)		$	(2,973	)		$	(2,879	)		$	(2,717	)		$	(9,971	)
Crude Oil Swaps
Contract volumes (Bbl)			30,000				—				—				—				30,000
Weighted-average fixed price per Bbl		$	87.50			$	—			$	—			$	—			$	87.50
Fair value, net		$	155			$	—			$	—			$	—			$	155
Total fair value, net		$	9,177			$	4,557			$	3,783			$	2,046			$	19,563

     During October 2010, the Company entered into new crude oil swap contracts for 48,000 barrels with an average contract price of $85.90 per barrel for 2011 and 42,000 barrels with an average price of $87.90 per barrel for 2012.

Note 5 — Fair Value Measurements

     The Company’s financial instruments include derivatives, debt, cash, receivables and payables. The carrying value of the Company’s debt approximates fair value due to the variable nature of the interest rates. The carrying amount of cash, receivables and payables approximates fair value because of the short-term nature of those instruments.

     As discussed in Note 3, White Deer’s investment in the Company included 7 ¹/2 year warrants to purchase common stock at an exercise price of $3.15 per share. Warrants to White Deer are recognized at fair value on the

date of issuance and recorded as a component of additional paid-in capital on the condensed consolidated balance sheet. See Note 3 for a discussion on the valuation of these warrants.

     Effective January 1, 2009, the Company adopted FASB ASC 820 Fair Value Measurements and Disclosures (“FASB ASC 820”), which applies to its nonfinancial assets and liabilities for which it discloses or recognizes at fair value on a nonrecurring basis, such as asset retirement obligations and other assets and liabilities. Fair value is the exit price that the Company would receive to sell an asset or pay to transfer a liability in an orderly transaction between market participants at the measurement date.

     FASB ASC 820 also establishes a hierarchy that prioritizes the inputs used to measure fair value. The three levels of the fair value hierarchy are as follows:

•

Level 1 — Quoted prices available in active markets for identical assets or liabilities as of the reporting date.

•

Level 2 — Pricing inputs other than quoted prices in active markets included in Level 1 which are either directly or indirectly observable as of the reporting date. Level 2 consists primarily of non-exchange traded commodity derivatives.

•

Level 3 — Pricing inputs include significant inputs that are generally less observable from objective sources.

     The Company classifies assets and liabilities within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement of each individual asset and liability taken as a whole. Certain derivatives are classified as Level 3 because observable market data is not available for all of the time periods for which the Company has derivative instruments. As observable market data becomes available for all of the time periods, these derivative positions will be reclassified as Level 2. The availability of market based information starting in July 2010 has allowed the Company to reclassify a portion of its swap contracts tied to Southern Star prices from Level 3 to Level 2 in the third quarter of 2010.

     ASU 2010-06, Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements requires reporting entities to provide information about movements of assets among Levels 1 and 2 of the three-tier fair value hierarchy established under FASB ASC 820. There were no movements between Levels 1 and 2 for the three month or nine month periods ending September 30, 2010 and 2009.

     The following table sets forth, by level within the fair value hierarchy, the assets and liabilities that were measured at fair value on a recurring basis as of the dates indicated (in thousands):

		Level				Level				Level				Total Net Fair
		1				2				3				Value
September 30, 2010
Commodity derivatives — assets		$	—			$	79,515			$	3,843			$	83,358
Commodity derivatives — liabilities		$	—			$	—			$	(9,418	)		$	(9,418	)
Total		$	—			$	79,515			$	(5,575	)		$	73,940
December 31, 2009 (Predecessor)
Commodity derivatives — assets		$	—			$	18,033			$	11,546			$	29,579
Commodity derivatives — liabilities		$	—			$	—			$	(10,016	)		$	(10,016	)
Total		$	—			$	18,033			$	1,530			$	19,563

     Risk management assets and liabilities in the table above represent the current fair value of all open derivative positions, excluding those derivatives designated as NPNS. These derivative instruments are classified as “Derivative financial instrument assets” or “Derivative financial instrument liabilities” in the condensed consolidated balance sheet.

     In order to determine the fair value of amounts presented above, the Company utilizes various factors including market data and assumptions that market participants would use in pricing assets or liabilities as well as assumptions about the risks inherent in the inputs to the valuation technique. These factors include not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and

parental guarantees), but also the impact of nonperformance risk on the Company’s liabilities. The Company utilizes observable market data for credit default swaps to assess the impact of non-performance credit risk when evaluating its assets from counterparties.

     In certain instances, the Company may utilize internal models to measure the fair value of derivative instruments. Generally, the Company uses similar models to value similar instruments. Valuation models utilize various inputs which include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, other observable inputs for the assets or liabilities, and market-corroborated inputs, which are inputs derived principally from or corroborated by observable market data by correlation or other means.

     The following table sets forth a reconciliation of changes in the fair value of risk management assets and liabilities classified as Level 3 in the fair value hierarchy (in thousands):

						Predecessor
		March 6, 2010,				January 1, 2010 to				Nine Months Ended
		September 30, 2010				March 5, 2010				September 30, 2009
Balance at beginning of period		$	5,455			$	1,530			$	60,947
Realized and unrealized gains included in earnings			13,390				7,254				25,309
Purchases, sales, issuances, and settlements			(7,964	)			(3,329	)			(74,215	)
Transfers into and out of Level 3			(16,456	)			—				—
Balance at end of period		$	(5,575	)		$	5,455			$	12,041

Note 6 — Asset Retirement Obligations

     The following table reflects the changes to the asset retirement liability for the period indicated (in thousands):

						(Predecessor)
		March 6, 2010				January 1, 2010
		to September 30, 2010				to March 5, 2010
Asset retirement obligations at beginning of period		$	6,648			$	6,552
Liabilities incurred			23				—
Liabilities settled			(22	)			(1	)
Accretion			340				97
Revisions in estimated cash flows			—				—
Asset retirement obligations at end of period		$	6,989			$	6,648

Note 7 — Share-Based Compensation

     Immediately prior to the recombination, there were 1,155,327 restricted shares of QRCP, 945,593 phantom units of QELP and 732,784 restricted units of QMLP that were unvested. In the recombination, 118,816 restricted shares of QRCP, 7,500 phantom units of QELP and 67,838 restricted units of QMLP were subject to immediate vesting immediately prior to the closing and, at closing, these awards converted to 36,416 shares of PostRock common stock. PostRock’s predecessor and the predecessor’s consolidated subsidiaries recognized $0.4 million of compensation expense related to the accelerated vesting discussed above. All remaining unvested awards were converted to 595,923 PostRock restricted share awards. In addition, 670,000 of QRCP stock options converted to 38,525 PostRock stock options upon effectiveness of the recombination. For the three months ended September 30, 2010, total share-based compensation related to stock awards and options of PostRock or its predecessor and consolidated subsidiaries of its predecessor was $0.4 million, compared to $0.3 million for the three months ended September 30, 2009. The stock based compensation expense was $1.0 million and $0.8 million for the periods from March 6 to September 30, 2010, and January 1 to March 5, 2010, respectively. The stock based compensation expense was $1.1 million for nine month period ended September 30, 2009. Share-based compensation is included in general and administrative expense on our statements of operations. The granting of future stock awards and options to employees subsequent to the recombination is governed by PostRock’s 2010 Long-Term Incentive Plan

(the “LTIP”). As of September 30, 2010, there were 835,964 shares available under the LTIP for future stock awards and options. Subsequent to the recombination, during 2010, 54,036 shares of PostRock stock were granted to officers and directors of the Company while 137,860 restricted shares and 18,975 stocks options were forfeited as a result of employee turnover. Total share-based compensation to be recognized on unvested stock awards and options as of September 30, 2010, is $1.2 million over a weighted average period of 1.53 years.

Note 8 — Earnings Per Share

     A reconciliation of the numerator and denominator used in the basic and diluted per share calculations for the periods indicated is as follows (dollars in thousands, except share and per share amounts):

						(Predecessor)
		Three Months				Three Months								(Predecessor)
		Ended				Ended				March 6, 2010				January 1,				Nine Months
		September				September				to September				2010 to March				Ended June
		30, 2010				30, 2009				30, 2010				5, 2010				30, 2009
Net income (loss) attributable to common stockholders		$	27,980			$	(11,527	)		$	35,403			$	11,778			$	(80,932	)
Denominator
Common shares			8,062,567				31,885,445				8,053,724				32,016,327				31,827,513
Unvested share-based awards participating (1)			—				—				—				121,121				—
Denominator for basic earnings per share			8,062,567				31,885,445				8,053,724				32,137,448				31,827,513
Effect of potentially dilutive securities
Unvested share-based awards non-participating			138,186				—				99,156				450,751				—
Warrants			517,895								227,973
Stock options			—				—				177				26,154				—
Denominator for diluted earnings per share			8,718,648				31,885,445				8,381,030				32,614,353				31,827,513
Basic earnings per share		$	3.47			$	(0.36	)		$	4.40			$	0.37			$	(2.54	)
Diluted earnings per share		$	3.21			$	(0.36	)		$	4.22			$	0.36			$	(2.54	)
Securities excluded from earnings per share calculation
Unvested share-based awards participating (1)(2)			—				160,232				—				—				160,232
Antidilutive stock options			19,550				700,000				19,550				570,000				700,000

Note 9— Impairment of Oil and Gas Properties

     At the end of each quarterly period, the unamortized cost of oil and natural gas properties, net of related deferred income taxes, is limited to the full cost ceiling, computed as the sum of the estimated future net revenues from proved reserves using twelve-month average prices discounted at 10%, and adjusted for related income tax effects (ceiling test). Prior to December 31, 2009, the present value was calculated using spot market prices at the balance sheet date. Under full cost accounting rules, any ceiling test write-downs of oil and natural gas properties may not be reversed in subsequent periods. Since the Company does not designate its derivative financial instruments as hedges, it is not allowed to use the impacts of the derivative financial instruments in its ceiling test computation. As a result, decreases in commodity prices which contribute to ceiling test write-downs may be offset by mark-to-market gains which are not reflected in the Company’s ceiling test results.

     Under the present full cost accounting rules, the Company is required to compute the after-tax present value of proved oil and natural gas properties using twelve-month average prices for oil and natural gas at the balance sheet

date. The base for the Company’s spot prices for natural gas is Henry Hub and for oil is Cushing, Oklahoma. The Predecessor had previously recognized a ceiling test impairment of $102.9 million during the first quarter of 2009 while no impairment has resulted in 2010. Natural gas, which is sold at other natural gas marketing hubs where the Company conducts operations, is subject to prices which reflect variables that can increase or decrease spot natural gas prices at these hubs such as market demand, transportation costs and quality of the natural gas being sold. Those differences are referred to as the basis differentials. In the past, basis differentials resulted in natural gas prices for the Company’s Cherokee Basin production to be lower than Henry Hub, except in Appalachia, where the Company has typically received a premium to Henry Hub. The Company may face further ceiling test write-downs in future periods, depending on the level of commodity prices, drilling results and well performance.

     The calculation of the ceiling test is based upon estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves, in projecting the future rates of production and in the timing of development activities. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, production and changes in economics related to the properties subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

Note 10 — Income Taxes

     The effective income tax rate for all periods presented was less than the federal statutory rate primarily due to the effect of changes in the valuation allowance on the net deferred tax asset.

     On March 5, 2010, the Company completed the recombination and, on September 21, 2010, the White Deer equity investment. Both transactions resulted in an ownership change for purposes of Internal Revenue Code Section 382 and significantly restrict the Company’s ability to utilize its otherwise available net operating loss (“NOL”) carryforwards. Accordingly, the Company has reduced its gross deferred tax assets for the NOL carryforwards that it does not believe will be utilized because of the restrictions imposed by Section 382, and has also reversed the associated valuation allowance recorded by the Company in prior periods against such NOLs.

     The Company has recorded no provision for income taxes for the pre-tax earnings for the three months and nine months ended September 30, 2009, for the three months ended September 30, 2010 and for the period from March 6, 2010 through September 30, 2010, as it believes that such earnings can be offset by its remaining unutilized NOLs from prior periods. The Company will continue to record a full valuation allowance against the remaining net deferred tax assets because it does not believe that it is more likely than not that the future tax benefits will be realized.

Note 11 — Commitments and Contingencies

Litigation

     The Company is subject, from time to time, to certain legal proceedings and claims in the ordinary course of conducting its business.

     Federal Securities Class Actions

Michael Friedman, individually and on behalf of all others similarly situated v. Quest Energy Partners LP, Quest Energy GP LLC, Quest Resource Corporation, Jerry Cash, and David E. Grose , Case No. 08-cv-936-M, U.S. District Court for the Western District of Oklahoma, filed September 5, 2008

James Jents, individually and on behalf of all others similarly situated v. Quest Resource Corporation, Jerry Cash, David E. Grose, and John Garrison, Case No. 08-cv-968-M, U.S. District Court for the Western District of Oklahoma, filed September 12, 2008

J. Braxton Kyzer and Bapui Rao, individually and on behalf of all others similarly situated v. Quest Energy Partners LP, Quest Energy GP LLC, Quest Resource Corporation and David E. Grose , Case No. 08-cv-1066-M, U.S. District Court for the Western District of Oklahoma, filed October 6, 2008

Paul Rosen, individually and on behalf of all others similarly situated v. Quest Energy Partners LP, Quest Energy GP LLC, Quest Resource Corporation, Jerry Cash, and David E. Grose , Case No. 08-cv-978-M, U.S. District Court for the Western District of Oklahoma, filed September 17, 2008

     Four putative class action complaints were filed in the United States District Court for the Western District of Oklahoma naming QRCP, QELP and Quest Energy GP, LLC, the general partner of the predecessor of QELP (“QEGP”), and certain of their then current and former officers and directors as defendants. The complaints were filed by certain stockholders on behalf of themselves and other stockholders who purchased QRCP common stock between May 2, 2005 and August 25, 2008 and QELP common units between November 7, 2007 and August 25, 2008. The complaints assert claims under Sections 10(b) and 20(a) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and Rule 10b-5 promulgated thereunder, and Sections 11 and 15 of the Securities Act of 1933. The complaints allege that the defendants violated the federal securities laws by issuing false and misleading statements and/or concealing material facts concerning certain unauthorized transfers of funds from subsidiaries of QRCP to entities controlled by QRCP’s former chief executive officer, Mr. Jerry D. Cash. The complaints also allege that, as a result of these actions, QRCP’s stock price and the unit price of QELP was artificially inflated during the class period. On December 29, 2008, the Court consolidated these complaints. Mediation was held among the parties on February 2 and April 2, 2010. An agreement to settle the federal court securities actions, both individual and class action, all federal court shareholder derivative suits and all state court derivative suits was reached in principle. The settlement is subject to court approval. On July 9, 2010, a stipulation of settlement was filed in the consolidated action. On August 13, 2010, the Court entered an order preliminarily approving the settlement. Notice of the proposed settlement has been sent to members of the putative class, who have until November 15, 2010, to submit a claim or to opt out of the settlement. Pursuant to the settlement agreement, the defendants may elect to terminate the settlement if more than five percent of the class members opt out. A hearing on final approval of the proposed settlement is set for November 29, 2010. If approved by the Court, all of the referenced lawsuits will be dismissed with prejudice to refiling. The Company is contributing $1.0 million to the proposed settlement of the lawsuits. In addition, the Company has agreed to pay approximately $0.4 million representing a portion of associated defense costs of certain individual defendants. As of September 30, 2010, the Company has paid $1.3 million of the amounts above. While the Company has recorded an accrual of $1.4 million through the third quarter of 2010, there can be no assurance that final approval of the settlement will be granted by the Court, that the defendants will not terminate the settlement if a sufficient number of the class members opt out or that the final settlement amount will equal the amount of the accrual.

     Federal Individual Securities Litigation

Bristol Capital Advisors v. Quest Resource Corporation, Inc., Jerry Cash, David E. Grose, and John Garrison, Case No. CIV-09-932, U.S. District Court for the Western District of Oklahoma, filed August 24, 2009

     On August 24, 2009, a complaint was filed in the United States District Court for the Western District of Oklahoma naming QRCP and certain then current and former officers and directors as defendants. The complaint was filed by an individual stockholder of QRCP. The complaint asserts claims under Sections 10(b) and 20(a) of the Exchange Act. The complaint alleges that the defendants violated the federal securities laws by issuing false and misleading statements and/or concealing material information concerning unauthorized transfers from subsidiaries of QRCP to entities controlled by QRCP’s former chief executive officer, Mr. Jerry D. Cash. The complaint also alleges that QRCP issued false and misleading statements and or/concealed material information concerning a misappropriation by its former chief financial officer, Mr. David E. Grose, of $1 million in company funds and receipt of unauthorized kickbacks of approximately $850,000 from a company vendor. The complaint also alleges that, as a result of these actions, QRCP’s stock price was artificially inflated when the plaintiff purchased their shares of QRCP common stock. As discussed above, an agreement to settle has been reached in principle. The settlement is subject to court approval and there can be no assurance that final approval of the settlement will be granted by the Court.

J. Steven Emerson, Emerson Partners, J. Steven Emerson Roth IRA, J. Steven Emerson IRA RO II, and Emerson Family Foundation v. Quest Resource Corporation, Inc., Quest Energy Partners L.P., Jerry Cash, David E. Grose, and John Garrison, Case No. 5:09-cv-1226-M, U.S. District Court for the Western District of Oklahoma, filed November 3, 2009

     On November 3, 2009, a complaint was filed in the United States District Court for the Western District of Oklahoma naming QRCP, QELP, and certain then current and former officers and directors as defendants. The complaint was filed by individual shareholders of QRCP stock and individual purchasers of QELP common units. The complaint asserts claims under Sections 10(b) and 20(a) of the Exchange Act. The complaint alleges that the defendants violated the federal securities laws by issuing false and misleading statements and/or concealing material information concerning unauthorized transfers from subsidiaries of QRCP to entities controlled by QRCP’s former chief executive officer, Mr. Jerry D. Cash. The complaint also alleges that QRCP and QELP issued false and misleading statements and/or concealed material information concerning a misappropriation by its former chief financial officer, Mr. David E. Grose, of $1 million in company funds and receipt of unauthorized kickbacks of approximately $850,000 from a company vendor. The complaint also alleges that, as a result of these actions, the price of QRCP stock and QELP common units was artificially inflated when the plaintiffs purchased QRCP stock and QELP common units. The plaintiffs seek $10 million in damages. As discussed above, an agreement to settle has been reached in principle. The settlement is subject to court approval and there can be no assurance that final approval of the settlement will be granted by the Court.

     Federal Derivative Cases

James Stephens, derivatively on behalf of nominal defendant Quest Resource Corporation v. William H. Damon III, Jerry Cash, David Lawler, David E. Grose, James B. Kite Jr., John C. Garrison and Jon H. Rateau, Case No. 08-cv-1025-M, U.S. District Court for the Western District of Oklahoma, filed September 25, 2008

     On September 25, 2008, a complaint was filed in the United States District Court for the Western District of Oklahoma, purportedly on QRCP’s behalf, which named certain of QRCP’s then current and former officers and directors as defendants. The factual allegations mirror those in the putative class actions described above, and the complaint asserts claims for breach of fiduciary duty, abuse of control, gross mismanagement, waste of corporate assets, and unjust enrichment. The complaint seeks disgorgement, costs, expenses, and equitable and/or injunctive relief. As discussed above, an agreement to settle has been reached in principle. The settlement is subject to court approval and there can be no assurance that final approval of the settlement will be granted by the Court.

William Dean Enders, derivatively on behalf of nominal defendant Quest Energy Partners, L.P. v. Jerry D. Cash, David E. Grose, David C. Lawler, Gary Pittman, Mark Stansberry, J. Philip McCormick, Douglas Brent Mueller, Mid Continent Pipe & Equipment, LLC, Reliable Pipe & Equipment, LLC, RHB Global, LLC, RHB, Inc., Rodger H. Brooks, Murrell, Hall, McIntosh & Co. PLLP, and Eide Bailly LLP, Case No. CIV-09-752-M, U.S. District Court for the Western District of Oklahoma, filed July 17, 2009

     On July 17, 2009, a complaint was filed in the United States District Court for the Western District of Oklahoma, purportedly on QELP’s behalf, which named certain of its then current and former officers and directors, external auditors and vendors. The factual allegations relate to, among other things, the transfers and lack of effective internal controls. The complaint asserts claims for breach of fiduciary duty, waste of corporate assets, unjust enrichment, conversion, disgorgement under the Sarbanes-Oxley Act of 2002, and aiding and abetting breaches of fiduciary duties against the individual defendants and vendors and professional negligence and breach of contract against the external auditors. The complaint seeks monetary damages, disgorgement, costs and expenses and equitable and/or injunctive relief. It also seeks injunctive relief requiring QELP to take all necessary actions to reform and improve its corporate governance and internal procedures. As discussed above, an agreement to settle has been reached in principle. The settlement is subject to court approval and there can be no assurance that final approval of the settlement will be granted by the Court.

     State Court Derivative Cases

Tim Bodeker, derivatively on behalf of nominal defendant Quest Resource Corporation v. Jerry Cash, David E. Grose, Bob G. Alexander, David C. Lawler, James B. Kite, John C. Garrison, Jon H. Rateau and William H. Damon III, Case No. CJ-2008-9042, District Court of Oklahoma County, State of Oklahoma, filed October 8, 2008

William H. Jacobson, derivatively on behalf of nominal defendant Quest Resource Corporation v. Jerry Cash, David E. Grose, David C. Lawler, James B. Kite, Jon H. Rateau, Bob G. Alexander, William H. Damon III, John C. Garrison, Murrell, Hall, McIntosh & Co., LLP, and Eide Bailly, LLP, Case No. CJ-2008-9657, District Court of Oklahoma County, State of Oklahoma, filed October 27, 2008

Amy Wulfert, derivatively on behalf of nominal defendant Quest Resource Corporation, v. Jerry D. Cash, David C. Lawler, Jon C. Garrison, John H. Rateau, James B. Kite Jr., William H. Damon III, David E. Grose, N. Malone Mitchell III, and Bryan Simmons, Case No. CJ-2008-9042 — consolidated December 30, 2008, District Court of Oklahoma County, State of Oklahoma (Original Case No. CJ-2008-9624, filed October 24, 2008)

     The factual allegations in these petitions mirror those in the putative class actions discussed above. All three petitions assert claims for breach of fiduciary duty, abuse of control, gross mismanagement, and unjust enrichment. The Jacobson petition also asserts claims against the two auditing firms named in that suit for professional negligence and aiding and abetting the director defendants’ breaches of fiduciary duties. The Wulfert petition also asserts a claim against Mr. Bryan Simmons for aiding and abetting Mr. Cash’s and Mr. Grose’s breaches of fiduciary duties. The petitions seek damages, costs, expenses, and equitable relief. On March 26, 2009, the court consolidated these actions as In re Quest Resource Corporation Shareholder Derivative Litigation, Case No. CJ-2008-9042. As discussed above, an agreement to settle has been reached in principle. The settlement is subject to court approval and there can be no assurance that final approval of the settlement will be granted by the Court.

     Royalty Owner Class Action

Hugo Spieker, et al. v. Quest Cherokee, LLC, Case No. 07-1225-MLB, U.S. District Court for the District of Kansas, filed August 6, 2007

     The Company was named as a defendant in a putative class action lawsuit filed by several royalty owners in the U.S. District Court for the District of Kansas. The putative class consists of all royalty and overriding royalty owners in the Kansas portion of the Cherokee Basin. Plaintiffs contend that the Company failed to properly make royalty payments by, among other things, paying royalties based on sale volumes rather than wellhead volumes, by allocating expenses in excess of actual costs, by improperly allocating production costs and marketing costs to royalty owners, and by failing to pay interest on royalty payments made late. The Company has filed an answer, denying plaintiffs’ claims.

     The parties participated in a mediation in August 2010 and continue to engage in settlement discussions. The Court has extended the previously entered stay of discovery to provide the parties with time to continue settlement discussions and/or conduct another mediation. The Company has recorded an accrual of $1.0 million related to this case.

     Litigation Related to Oil and Gas Leases

Billy Bob Willis, et al. v. Quest Resource Corporation, et al., Case No. CJ-09-063, District Court of Nowata County, State of Oklahoma, filed April 28, 2009

Larry Reitz, et al. v. Quest Resource Corporation, et al., Case No. CJ-09-076, District Court of Nowata County, State of Oklahoma, filed May 22, 2009

     The above-referenced lawsuits, which were filed in April and May 2009, respectively, have been consolidated to proceed as a single action. The plaintiffs plan to amend to assert a putative class of Oklahoma royalty interest owners within the Cherokee Basin. Plaintiffs allege that defendants have wrongfully deducted costs from the

royalties of plaintiffs and have engaged in self-dealing contracts and agreements resulting in a less than market price for production. Plaintiffs seek unspecified actual and punitive damages. Limited discovery has taken place and no deadlines have been set. The parties have agreed to participate in a mediation and are working toward scheduling the same.

Contractual Commitments

     The Company has numerous contractual commitments in the ordinary course of business, debt service requirements and operating lease commitments. Commitments as of December 31, 2009, are disclosed within Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations-Contractual Obligations in the Company’s 2009 Form 10-K. In July 2010, the Company entered into an investment advisory agreement in conjunction with its efforts to sell certain oil and gas properties in Appalachia. The agreement does not require a minimum payment but instead specifies payment amounts that are contingent on the successful sale of the properties and amount of proceeds from such sale. Other than the preceding contract and the restructuring of the Company’s credit agreements as described in Note 2, as of September 30, 2010, there were no other material changes to the Company’s commitments compared with December 31, 2009.

Note 12 — Operating Segments

     Operating segment data for the periods indicated is as follows (in thousands):

										Other and
		Oil and Gas				Natural Gas				Intersegment
		Production				Pipelines				Eliminations				Total
Three months ended September 30, 2010
Total revenues		$	21,484			$	11,827			$	(7,988	)		$	25,323
Inter-segment revenues			—				(7,988	)			7,988				—
Third-party revenues		$	21,484			$	3,839			$	—			$	25,323
Segment operating profit (loss)		$	4,630			$	3,484			$	—			$	8,114
Three months ended September 30, 2009 (Predecessor)
Total revenues		$	18,329			$	16,635			$	(11,002	)		$	23,962
Inter-segment revenues			—				(11,002	)			11,002				—
Third-party revenues		$	18,329			$	5,633			$	—			$	23,962
Segment operating profit (loss)		$	(11,342	)		$	4,254			$	—			$	(7,088	)
March 6, 2010 to September 30, 2010
Total revenues		$	50,075			$	27,426			$	(18,524	)		$	58,977
Inter-segment revenues			—				(18,524	)			18,524				—
Third-party revenues		$	50,075			$	8,902			$	—			$	58,977
Segment operating profit (loss)		$	9,245			$	8,091			$	—			$	17,336
January 1, 2010 to March 5, 2010 (Predecessor)
Total revenues		$	18,659			$	7,788			$	(4,963	)		$	21,484
Inter-segment revenues			—				(4,963	)			4,963				—
Third-party revenues		$	18,659			$	2,825			$	—			$	21,484
Segment operating profit		$	5,314			$	2,251			$	—			$	7,565
Nine Months ended September 30, 2009 (Predecessor)
Total revenues		$	56,711			$	52,260			$	(31,238	)		$	77,733
Inter-segment revenues			—				(31,238	)			31,238				—
Third-party revenues		$	56,711			$	21,022			$	—			$	77,733
Segment operating profit (loss)		$	(128,246	)		$	17,840			$	—			$	(110,406	)
Identifiable assets
September 30, 2010		$	171,237			$	148,079			$	—			$	319,316
December 31, 2009 (Predecessor)		$	128,548			$	155,107			$	—			$	283,655