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

Commission file number: 001-34635

POSTROCK ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

Delaware		27-0981065
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer 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):

     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 May 1, 2010, there were 8,038,974 shares of common stock of PostRock Energy Corporation outstanding.

 

 

POSTROCK ENERGY CORPORATION
FORM 10-Q
FOR THE QUARTER ENDED MARCH 31, 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			9
Item 4. Controls and Procedures			10
PART II — OTHER INFORMATION
Item 1. Legal Proceedings			13
Item 1A. Risk Factors			13
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			13
Item 3. Defaults Upon Senior Securities			13
Item 5. Other Information			13
Item 6. Exhibits			14
SIGNATURES			17
EX-10.15
EX-10.16
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
CONDENSED CONSOLIDATED BALANCE SHEETS
(in thousands, except share and per share data)

						(Predecessor)
		March 31, 2010				December 31, 2009
		(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	27,361			$	20,884
Restricted cash			564				718
Accounts receivable — trade, net			13,368				13,707
Other receivables			1,350				2,269
Other current assets			7,288				8,141
Inventory			8,009				9,702
Current derivative financial instrument assets			28,832				10,624
Total current assets			86,772				66,045
Oil and gas properties under full cost method of accounting, net			41,878				40,478
Pipeline assets, net			137,675				136,017
Other property and equipment, net			19,113				19,433
Other assets, net			2,986				2,727
Long-term derivative financial instrument assets			39,380				18,955
Total assets		$	327,804			$	283,655
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable		$	15,746			$	10,852
Revenue payable			5,585				5,895
Accrued expenses			11,062				11,417
Current portion of notes payable			310,072				310,015
Current derivative financial instrument liabilities			2,085				1,447
Total current liabilities			344,550				339,626
Long-term derivative financial instrument liabilities			9,552				8,569
Other liabilities			6,687				6,552
Notes payable			17,765				19,295
Commitments and contingencies
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; none issued and outstanding			—
Common stock, $0.01 par value; authorized shares — 40,000,000; issued and outstanding —8,038,974			80
Additional paid-in capital			367,795				299,010
Treasury stock, at cost							(7	)
Accumulated deficit			(418,625	)			(447,413	)
Total stockholders’ deficit before non-controlling interests			(50,750	)			(148,377	)
Non-controlling interests							57,990
Total equity			(50,750	)			(90,387	)
Total liabilities and equity		$	327,804			$	283,655

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

POSTROCK ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
(Unaudited)

						(Predecessor)
										Three Months
		March 6, 2010 to				January 1, 2010				Ended March
		March 31, 2010				to March 5, 2010				31, 2009
Revenue:
Oil and gas sales		$	8,471			$	18,659			$	22,275
Gas pipeline revenue			1,357				2,825				7,803
Total revenues			9,828				21,484				30,078
Costs and expenses:
Oil and gas production			2,505				5,266				7,686
Pipeline operating			2,250				4,489				7,160
General and administrative			3,154				5,735				7,882
Depreciation, depletion and amortization			1,103				4,164				16,120
Impairment of oil and gas properties			—				—				102,902
Total costs and expenses			9,012				19,654				141,750
Operating income (loss)			816				1,830				(111,672	)
Other income (expense):
Gain (loss) from derivative financial instruments			18,573				25,246				39,464
Other income (expense), net			(281	)			(4	)			56
Interest expense, net			(2,098	)			(5,336	)			(6,888	)
Total other income (expense)			16,194				19,906				32,632
Income (loss) before income taxes and non-controlling interests			17,010				21,736				(79,040	)
Income tax expense			—				—				—
Net income (loss)			17,010				21,736				(79,040	)
Net (income) loss attributable to non-controlling interest			—				(9,958	)			27,654
Net income (loss) attributable to controlling interest		$	17,010			$	11,778			$	(51,386	)
Net income (loss) per common share:
Basic		$	2.12			$	0.37			$	(1.62	)
Diluted		$	2.04			$	0.36			$	(1.62	)
Weighted average shares outstanding:
Basic			8,038				32,137				31,741
Diluted			8,348				32,614				31,741

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

POSTROCK ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
(Unaudited)

						(Predecessor)
										Three Months
		March 6, 2010 to				January 1, 2010				Ended March
		March 31, 2010				to March 5, 2010				31, 2009
Cash flows from operating activities:
Net income (loss)		$	17,010			$	21,736			$	(79,040	)
Adjustments to reconcile net income (loss) to cash provided by operations:
Depreciation, depletion and amortization			1,103				4,164				16,120
Stock-based compensation			83				808				487
Impairment of oil and gas properties			—				—				102,902
Amortization of deferred loan costs			396				2,094				576
Change in fair value of derivative financial instruments			(15,439	)			(21,573	)			(22,630	)
Loss (gain) on disposal of property and equipment			172				—				—
Other non-cash changes to items affecting net income			111				—				—
Change in assets and liabilities:
Accounts receivable			576				(237	)			955
Other receivables			(95	)			1,014				2,700
Other current assets			(2,072	)			466				248
Other assets			(477	)			2				579
Accounts payable			2,814				(83	)			(10,094	)
Revenue payable			(153	)			(157	)			(395	)
Accrued expenses			249				983				861
Other long-term liabilities			(4	)			—				(1	)
Other			—				—				(6	)
Cash flows from operating activities			4,274				9,217				13,262
Cash flows from investing activities:
Restricted cash			155				(1	)			24
Proceeds from sale of oil and gas properties			—				—				8,730
Equipment, development, leasehold and pipeline			(2,241	)			(2,282	)			(4,003	)
Cash flows from investing activities			(2,086	)			(2,283	)			4,751
Cash flows from financing activities:
Proceeds from bank borrowings			—				—				150
Repayments of bank borrowings			(4,004	)			(41	)			(4,932	)
Proceeds from revolver			500				900				—
Repayments of revolver note			—				—				—
Refinancing costs			—				—				(37	)
Cash flows from financing activities			(3,504	)			859				(4,819	)
Net increase (decrease) in cash			(1,316	)			7,793				13,194
Cash and cash equivalents beginning of period			28,677				20,884				13,785
Cash and cash equivalents end of period		$	27,361			$	28,677			$	26,979

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

POSTROCK ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF EQUITY
FOR THE THREE MONTHS ENDED MARCH 31, 2010
(Amounts subsequent to December 31, 2009 are unaudited)
(in thousands)

																						Total
																						Stockholders’
		Common								Additional												Deficit Before
		Shares				Common				Paid-in				Treasury				Accumulated				Non-controlling				Non-controlling				Total
		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	)
Successor:
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			—				—				83				—				—				83				—				83
Net income							—				—				—				17,010				17,010				—				17,010
Balance, March 31, 2010			8,038,974			$	80			$	367,795			$	—			$	(418,625	)		$	(50,750	)		$	—			$	(50,750	)

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

POSTROCK ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2010
(Unaudited)

Note 1 — Basis of Presentation

     PostRock Energy Corporation (“PostRock” or “Successor”) is a Delaware corporation formed on July 1, 2009 for the purpose of effecting the recombination of Quest Resource Corporation (now named PostRock Energy Services Corporation) (“QRCP”), Quest Energy Partners, L.P. (now named PostRock MidContinent Production, LLC) (“QELP”) and Quest Midstream Partners, L.P. (now named PostRock Midstream, LLC) (“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 integrated 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 and the Appalachian Basin in West Virginia and New York. The Company’s Appalachian Basin operations are primarily focused on the development of the Marcellus Shale. Its Cherokee Basin operations are currently focused on developing coal bed methane (“CBM”) gas production, which is served by a gas gathering pipeline network. The Company also owns an interstate natural gas transmission pipeline.

     The (a) condensed consolidated balance sheet as of December 31, 2009, which has been derived from audited financial statements, and (b) 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 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.

Going Concern

     The accompanying condensed consolidated financial statements have been prepared assuming that we will continue as a going concern, which contemplates the realization of assets and the liquidation of liabilities in the normal course of business, though such an assumption may not be true. We have incurred significant losses from 2003 through 2009, mainly attributable to operations, the impairment of our assets, legal restructurings, financings, the legal and operational structure that existed prior to recombination, expenditures resulting from the investigation related to the misappropriation of funds by our former chief executive officer and our recent recombination activities. While we successfully negotiated amendments to our various credit facilities allowing us to accomplish the recombination, current payment obligations under these facilities as of March 31, 2010 were $310.1 million, of which $2.4 million was paid in April 2010 and $15.8 million will be payable on July 11, 2010. We and our financial advisor are actively pursuing the refinancing of our credit facilities. There can be no assurance that we will be successful in these efforts, which raises substantial doubt as to our ability to continue as a going concern. The condensed consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Recent Accounting Pronouncements and Recently Adopted Accounting Pronouncements

     In June 2009, the Financial Accounting Standards Board (“FASB”) issued FASB Accounting Standards Codification (“FASB ASC”) 105 Generally Accepted Accounting Principles, which establishes FASB ASC as the sole source of authoritative GAAP. Pursuant to the provisions of FASB ASC 105, the Company is currently disclosing updated references to GAAP in its financial statements. The adoption of this standard did not have a material impact on our consolidated financial statements.

     In January 2010, the 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 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 beginning with the quarter ended March 31, 2010 and 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

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

						(Predecessor)
		March 31,				December 31,
		2010				2009
Borrowings under bank senior credit facilities:
QRCP:
Term Loan		$	31,091			$	30,108
Revolving Line of Credit			5,700				4,300
Promissory Notes			1,292				1,250
QELP:
Quest Cherokee Credit Agreement			141,000				145,000
Second Lien Loan Agreement			29,969				29,821
QMLP:
Credit Agreement			118,728				118,728
Notes payable to banks and finance companies			57				103
Total debt			327,837				329,310
Less current maturities included in current liabilities			310,072				310,015
Total long-term debt		$	17,765			$	19,295

     The terms of our credit facilities are described within Item 8. Financial Statement and Supplementary Data in the 2009 Form 10-K. Upon closing of the recombination, the maturities of QELP’s and QMLP’s debt agreements were extended to March 11, 2011. During the first quarter of 2010, $1.4 million was borrowed on QRCP’s revolving line of credit, the outstanding amounts under QRCP’s term loan and promissory notes were increased by a total of $1.0 million from the accrual of interest and $4.0 million was repaid on the Quest Cherokee Credit Agreement. PostRock was in compliance with all of its financial covenants as of March 31, 2010.

Note 3 — Derivative Financial Instruments

     We are exposed to commodity price and interest rate risk, and management believes it prudent to periodically reduce our exposure to cash-flow variability resulting from this volatility. Accordingly, we enter into certain derivative financial instruments in order to manage exposure to commodity price risk inherent in our oil and gas production operations. Specifically, we 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. We monitor the creditworthiness of each counterparty and assess the impact, if any, on fair value. In addition, we routinely exercise our contractual right to net realized gains against realized losses when settling with our swap and option counterparties.

     We account for our derivative financial instruments in accordance with FASB ASC 815 Derivatives and Hedging. 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. ASC Topic 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. We do not designate our derivative financial instruments as hedging instruments for financial accounting purposes, and, as a result, we recognize the change in the respective instruments’ fair value currently in earnings. In accordance with FASB ASC 815, the table below outlines the classification of our

derivative financial instruments on our condensed consolidated balance sheets and their financial impact in our condensed consolidated statements of operations as of and for the periods indicated (in thousands):

Fair Value of Derivative Financial Instruments

										(Predecessor)
						March 31,				December 31,
Derivative Financial Instruments		Balance Sheet location				2010				2009
Commodity contracts		Current derivative financial instrument asset				$	28,832			$	10,624
Commodity contracts		Long-term derivative financial instrument asset					39,380				18,955
Commodity contracts		Current derivative financial instrument liability					(2,085	)			(1,447	)
Commodity contracts		Long-term derivative financial instrument liability					(9,552	)			(8,569	)
						$	56,575			$	19,563

     Settlements in the normal course of maturities of our derivative financial instrument contracts result in cash receipts from or cash disbursement to our derivative contract counterparties and are, therefore, realized gains or losses. Changes in the fair value of our 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)
		March 6, 2010				January 1,				Three Months
		to March 31,				2010 to March				Ended March
		2010				5, 2010				31, 2009
Realized gains (losses)		$	3,134			$	3,673			$	16,834
Unrealized gains (losses)			15,439				21,573				22,630
Total		$	18,573			$	25,246			$	39,464

     The following table summarizes the estimated volumes, fixed prices and fair values attributable to oil and gas derivative contracts as of March 31, 2010:

		Remainder of				Year Ending December 31,
		2010				2011				2012				2013				Total
Natural Gas Swaps:
Contract volumes (Mmbtu)			12,251,218				13,550,302				11,000,004				9,000,003				45,801,527
Weighted-average fixed price per Mmbtu		$	5.97			$	6.80			$	7.13			$	7.28			$	6.75
Fair value, net		$	22,782			$	20,509			$	14,723			$	10,141			$	68,155
Basis Swaps:
Contract volumes (Mmbtu)			2,834,118				8,549,998				9,000,000				9,000,003				29,384,119
Weighted-average fixed price per Mmbtu		$	(0.65	)		$	(0.67	)		$	(0.70	)		$	(0.71	)		$	(0.69	)
Fair value, net		$	(1,239	)		$	(3,756	)		$	(3,660	)		$	(2,982	)		$	(11,637	)
Crude Oil Swaps:
Contract volumes (Bbl)			22,500				—				—				—				22,500
Weighted-average fixed price per Bbl		$	87.50			$	—			$	—			$	—			$	87.50
Fair value, net		$	57			$	—			$	—			$	—			$	57
Total fair value, net		$	21,600			$	16,753			$	11,063			$	7,159			$	56,575

     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

Note 4 — Fair Value Measurements

     Our financial instruments include commodity derivatives, debt, cash, receivables and payables. The carrying value of our 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.

     Effective January 1, 2009, we adopted FASB ASC 820 Fair Value Measurements and Disclosures, which applies to our nonfinancial assets and liabilities for which we disclose or recognize at fair value on a nonrecurring basis, such as asset retirement obligations and other assets and liabilities. Fair value is the exit price that we 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.

     We classify 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 of our derivatives are classified as Level 3 because observable market data is not available for all of the time periods for which we have derivative instruments. As observable market data becomes available for all of the time periods, these derivative positions will be reclassified as Level 2.

     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 periods ending March 31, 2010 and 2009.

     The following table sets forth, by level within the fair value hierarchy, our 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
March 31, 2010
Commodity derivatives — assets		$	—			$	42,606			$	25,606			$	68,212
Commodity derivatives — liabilities		$	—			$	—			$	(11,637	)		$	(11,637	)
Total		$	—			$	42,606			$	13,969			$	56,575
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. We classify all of these derivative instruments as “Derivative financial instrument assets” or “Derivative financial instrument liabilities” in our condensed consolidated balance sheets.

     In order to determine the fair value of amounts presented above, we utilize 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 our nonperformance risk on our liabilities. We utilize observable market data for credit default swaps to assess the impact of non-performance credit risk when evaluating our assets from counterparties.

     In certain instances, we may utilize internal models to measure the fair value of our derivative instruments. Generally, we use 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):

		March 6, 2010 to March
		31, 2010
Balance at beginning of period		$	5,455
Realized and unrealized gains included in earnings			11,275
Purchases, sales, issuances, and settlements			(2,761	)
Transfers into and out of Level 3			—
Balance at end of period		$	13,969

		(Predecessor)
		January 1, 2010 to
		March 5, 2010
Balance at beginning of period		$	1,530
Realized and unrealized gains included in earnings			7,254
Purchases, sales, issuances, and settlements			(3,329	)
Transfers into and out of Level 3			—
Balance at end of period		$	5,455

		(Predecessor)
		Three Months Ended
		March 31, 2009
Balance at beginning of period		$	60,947
Realized and unrealized gains included in earnings			39,516
Purchases, sales, issuances, and settlements			(17,421	)
Transfers into and out of Level 3			—
Balance as of March 31, 2009		$	83,042

Note 5 — Asset Retirement Obligations

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

		Period from March 6,
		2010 to March 31, 2010
Asset retirement obligations at beginning of period		$	6,648
Liabilities incurred			1
Liabilities settled			(4	)
Accretion			42
Revisions in estimated cash flows			—
Asset retirement obligations at end of period		$	6,687

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

Note 6 — Equity and Earnings per Share

     Share-Based Payments — 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 March 31, 2010, total share-based compensation related to stock awards and options of PostRock or its predecessor and consolidated subsidiaries of its predecessor was $0.9 million, compared to $0.5 million for the three months ended March 31, 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 our employees subsequent to the recombination is governed by PostRock’s 2010 Long-Term Incentive Plan (the “LTIP”). As of March 31, 2010 there were 850,000 shares available under the LTIP for future stock awards and options. Total share-based compensation to be recognized on unvested stock awards and options as of March 31, 2010 is $2.1 million over a weighted average period of 1.62 years.

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

		(Predecessor)
						Three Months
		January 1, 2010				Ended March
		to March 5, 2010				31, 2009
QELP
Beginning of period		$	15,350			$	58,666
Net income (loss) attributable to non-controlling interest			10,365				(29,321	)
Stock compensation expense related to QELP unit-based awards			167				33
End of period		$	25,882			$	29,378
QMLP
Beginning of period		$	42,640			$	145,870
Net income (loss) attributable to non-controlling interest			(407	)			1,667
Stock compensation expense related to QMLP unit-based awards			431				161
End of period		$	42,664			$	147,698
Total non-controlling interest at end of period		$	68,546			$	177,076

     Income/(Loss) 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
		March 6, 2010 to				January 1, 2010				Ended March
		March 31, 2010				to March 5, 2010				31, 2009
Net income (loss) attributable to common stockholders		$	17,010			$	11,778			$	(51,386	)
Denominator:
Common shares			8,038,974				32,016,327				31,740,569
Unvested share-based awards participating (1)			—				121,121				—
Denominator for basic earnings per share			8,038,974				32,137,448				31,740,569
Effect of potentially dilutive securities:
Unvested share-based awards non-participating			308,093				450,751				—
Stock options			1,423				26,154				—
Denominator for diluted earnings per share			8,348,490				32,614,353				31,740,569
Basic earnings per share		$	2.12			$	0.37			$	(1.62	)
Diluted earnings per share		$	2.04			$	0.36			$	(1.62	)
Securities excluded from earnings per share calculation:
Unvested share-based awards participating (1)(2)			—				—				359,049
Antidilutive stock options			32,775				570,000				700,000

Note 7 — 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 our 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. In the event our capitalized costs exceed the ceiling limitation at the end of the reporting date, we subsequently evaluate the limitation based on price changes that occur after the balance sheet date to assess impairment as currently permitted by Staff Accounting Bulletin Topic 12—Oil and Gas Producing Activities. Under full cost accounting rules, any ceiling test write-downs of oil and natural gas properties may not be reversed in subsequent periods. Since we do not designate our derivative financial instruments as hedges, we are not allowed to use the impacts of the derivative financial instruments in our 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 our ceiling test results.

     Under the present full cost accounting rules, we are required to compute the after-tax present value of our proved oil and natural gas properties using twelve-month average prices for oil and natural gas at our balance sheet date. The base for our 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 was necessary for the period from January 1 to March 5, 2010 or for the period from March 6 to March 31, 2010. Natural gas, which is sold at other natural gas marketing hubs where we conduct 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 our Cherokee Basin production which were lower than Henry Hub, except in Appalachia, where we have typically received a premium to Henry Hub. We 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 8 — Income Taxes

     The effective income tax rate of the Predecessor for the three months ended March 31, 2009 and for the period from January 1, 2010 through March 5, 2010 is 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 which should result in an ownership change for purposes of Internal Revenue Code Section 382 and should 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 period from March 6, 2010 through March 31, 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 9 — Commitments and Contingencies

Litigation

     We are subject, from time to time, to certain legal proceedings and claims in the ordinary course of conducting our 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 as 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, in the Western District of Oklahoma. On September 24, 2009, the court appointed lead plaintiffs for each of the QRCP class and the QELP class. The lead plaintiffs must file a consolidated amended complaint within 60 days after being appointed. On October 13, 2009, the plaintiffs filed a motion for partial modification of the Private Securities Litigation Reform Act of 1995 discovery stay, which the defendants opposed and which the court denied on December 15, 2009. On November 4, 2009, the court granted the lead plaintiffs’ unopposed request to file separate consolidated amended complaints. The court ordered that all pleadings and filings for the QELP class be filed under Friedman v. Quest Energy Partners, LP, et al. , case no. CIV-08-936-M, and all pleadings and filings for the QRCP class be filed under Jents v. Quest Resource Corporation, et al. , case no. CIV-08-968-M. The QELP lead plaintiffs filed a consolidated complaint on November 10, 2009. The consolidated complaint names as additional defendants David C. Lawler, Gary Pittman, Mark Stansberry, Murrell Hall, McIntosh & Co. PLLP, and Eide Bailly LLP. The QRCP lead plaintiffs filed a consolidated complaint on December 7, 2009, which names Murrell, Hall, McIntosh & Co. PLLP, Eide Bailly LLP, and various former QRCP directors as additional defendants. On December 23, 2009, QRCP and David C. Lawler filed a motion to dismiss the Friedman complaint, and on December 28, 2009, QELP, QEGP, Gary Pittman and Mark Stansberry filed a motion to dismiss the Friedman complaint. On January 21, 2010, QRCP and the individual director defendants filed a motion to dismiss the Jents complaint. No response to the motion to dismiss has yet been filed in either proceeding. On February 2, 2010, a mediation was held among the parties. A second round of the mediation was held on April 2, 2010. An agreement to settle all of the federal securities lawsuits has been reached in principle. The Company is awaiting preparation and execution of a formal settlement agreement, which will be subject to Court approval. We are contributing $1 million to the proposed settlement of the lawsuits. We have accrued additional sums to pay for anticipated further costs in connection with the lawsuits. We have recorded an accrual for these amounts but there can be no assurance that we will finalize the settlement agreement 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. An agreement to settle has been reached in principle. The Company is awaiting preparation and execution of a formal settlement agreement which will be subject to Court approval. There can be no assurance that we will finalize the settlement agreement.

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. An agreement to settle has been reached in principle. The Company is awaiting preparation and execution of a formal settlement agreement which will be subject to Court approval. There can be no assurance that we will finalize the settlement agreement.

     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 purported 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. On October 16, 2008, the court stayed this case pending the court’s ruling on any motions to dismiss the class action claims. Proceedings in this matter are currently stayed. Parties are in discussions to resolve all derivative cases in conjunction with settlement of the securities cases.

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-F, 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 QELP to take all necessary actions to reform and improve its corporate governance and internal procedures. On September 8, 2009, the case was transferred to Judge Miles-LaGrange, who is presiding over the other federal cases, and the case number was changed to CIV-09-752-M. All proceedings in this matter are currently stayed under Judge Miles-LaGrange’s order of October 16, 2009. Parties are in discussions to resolve all derivative cases in conjunction with settlement of the securities cases.

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 purported 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 Messrs. Cash’s and 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. Under the court’s order, the defendants need not respond to the individual petitions. The action is stayed by agreement of the parties until the motions to dismiss in the pending federal securities class action litigation are decided. Parties are in discussions to resolve all derivative cases in conjunction with settlement of the securities cases.

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

     Quest Cherokee, a wholly-owned subsidiary of QELP, 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 case was filed by the named plaintiffs on behalf of a putative class consisting of all Quest Cherokee’s royalty and overriding royalty owners in the Kansas portion of the Cherokee Basin. Plaintiffs contend that Quest Cherokee failed to properly make royalty payments to them and the putative class by, among other things, paying royalties based on reduced volumes instead of volumes measured at the wellheads, by allocating expenses in excess of the actual costs of the services represented, by allocating production costs to the royalty owners, by improperly allocating marketing costs to the royalty owners, and by making the royalty payments after the statutorily proscribed time for doing so without providing the required interest. Quest Cherokee has answered the complaint and denied plaintiffs’ claims. On July 21, 2009, the court granted plaintiffs’ motion to compel production of Quest Cherokee’s electronically stored

information, or ESI, and directed the parties to decide upon a timeframe for producing Quest Cherokee’s ESI. Quest Cherokee’s most recent offer, for which it has recorded an accrual, was for $1.0 million to resolve claims for all past royalty payments, and a proposed formula for resolving the issue of future gathering rates. To date, we have not received plaintiffs’ response to the proposal. Previously, discovery was stayed until April 14, 2010 to allow the parties to discuss settlement terms. In light of the ongoing settlement discussions, Quest Cherokee is asking the Court to continue the stay for an additional 30 days.

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

     QRCP et al. have been named in the above-referenced lawsuit. Plaintiffs are royalty owners who allege that the defendants have wrongfully deducted costs from the royalties of plaintiffs and have engaged in self-dealing contracts resulting in less than market price for the gas production. Plaintiffs pray for unspecified actual and punitive damages. The defendants have filed a motion to dismiss certain tort claims, but no ruling has yet been issued by the Court. Limited pretrial discovery has occurred. No court deadlines have been set. QRCP intends to defend vigorously against the plaintiffs’ claims.

Contractual Commitments

     We have numerous contractual commitments in the ordinary course of business, debt service requirements and operating lease commitments. Our 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 our 2009 Form 10-K. On February 2010, we extended an investment advisory service agreement that would have otherwise expired for an additional five months in exchange for monthly payments of $50,000. We also entered into an equity financing advisory agreement in February 2010 that would require a minimum payment of $750,000 payable on June 30, 2010. Other than the preceding contracts, there are no other material changes to our commitments since December 31, 2009.

Note 10 — Operating Segments

     In our Quarterly Report on Form 10-Q for the quarter ended March 31, 2009, we overstated the intercompany transportation revenue related to our natural gas pipeline segment and the corresponding intercompany transportation expense related to our oil and gas production segment by $2.2 million. As a result, our measure of segment profitability related to the natural gas pipeline segment was overstated by $2.2 million while segment profitability related to the oil and natural gas production segment was understated by the same amount. The error did not affect consolidated total revenues or net income for the period. The disclosure below reflects correction of the misstatement discussed above. Operating segment data for the periods indicated is as follows (in thousands):

										Other and
		Oil and Gas				Natural Gas				Intersegment
		Production				Pipelines				Eliminations				Total
March 6, 2010 to March 31, 2010:
Total revenues		$	8,471			$	4,108			$	(2,751	)		$	9,828
Inter-segment revenues			—				(2,751	)			2,751				—
Third-party revenues		$	8,471			$	1,357			$	—			$	9,828
Segment operating profit (loss)		$	2,610			$	1,360			$	—			$	3,970
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
Three months ended March 31, 2009 (Predecessor):
Total revenues		$	22,275			$	18,086			$	(10,283	)		$	30,078
Inter-segment revenues			—				(10,283	)			10,283				—
Third-party revenues		$	22,275			$	7,803			$	—			$	30,078
Segment operating profit (loss)		$	(110,749	)		$	6,959			$	—			$	(103,790	)
Identifiable assets:
March 31, 2010		$	170,885			$	156,919			$	—			$	327,804
December 31, 2009 (Predecessor)		$	128,548			$	155,107			$	—			$	283,655

     The following table reconciles segment operating profits reported above to income (loss) before income taxes and non-controlling interests (in thousands):

						Predecessor
										Three Months
		March 6, 2010 to				January 1, 2010				Ended March 31,
		March 31, 2010				to March 5, 2010				2009
Segment operating profit (loss) (1)		$	3,970			$	7,565			$	(103,790	)
General and administrative expenses			(3,154	)			(5,735	)			(7,882	)
Gain (loss) from derivative financial instruments			18,573				25,246				39,464
Interest expense, net			(2,098	)			(5,336	)			(6,888	)
Other income (expense), net			(281	)			(4	)			56
Income (loss) before income taxes and noncontrolling interests		$	17,010			$	21,736			$	(79,040	)

Note 11 — Subsequent Events

     On May 10, 2010, a tornado struck our oil producing property located just north of Seminole County in Central Oklahoma. The tornado destroyed a building housing one of our pump stations and the fiberglass tanks associated with it. It also did extensive damage to the power grid. We are currently assessing the full extent of the damage, although we do not believe the impact to be material to our operations.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Forward-looking statements

     Various statements in this report, including those that express a belief, expectation, or intention, as well as those that are not statements of historical fact, are forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These statements include those regarding projections and estimates concerning the timing and success of specific projects; financial position; business strategy; budgets; amount, nature and timing of capital expenditures; drilling of wells and construction of pipeline infrastructure; acquisition and development of oil and natural gas properties and related pipeline infrastructure; timing and amount of future production of oil and natural gas; operating costs and other expenses; estimated future net revenues from oil and natural gas reserves and the present value thereof; cash flow and anticipated liquidity; funding of our capital expenditures; ability to meet our debt service obligations; and other plans and objectives for future operations.

     When we use the words “believe,” “intend,” “expect,” “may,” “will,” “should,” “anticipate,” “could,” “estimate,” “plan,” “predict,” “project,” or their negatives, or other similar expressions, the statements which include those words are usually forward-looking statements. When we describe strategy that involves risks or uncertainties, we are making forward-looking statements. The factors impacting these risks and uncertainties include, but are not limited to:

	•		current weak economic conditions;
	•		our current financial condition and liquidity constraints;
	•		volatility of oil and natural gas prices;
	•		benefits or effects of the recombination;
	•		increases in the cost of drilling, completion and gas gathering or other costs of developing and producing our reserves;
	•		our restrictive debt covenants;
	•		access to capital, including debt and equity markets;
	•		results of our hedging activities;
	•		drilling, operational and environmental risks; and
	•		regulatory changes and litigation risks.

     You should consider carefully the statements in Part I, Item 1A. “Risk Factors” of our 2009 Form 10-K and other sections of this Quarterly Report on Form 10-Q, which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements.

     We have based these forward-looking statements on our current expectations and assumptions about future events. The forward-looking statements in this report speak only as of the date of this report; we disclaim any obligation to update these statements unless required by securities law, and we caution you not to rely on them unduly. Readers are urged to carefully review and consider the various disclosures made by us in our reports filed with the SEC, which attempt to advise interested parties of the risks and factors that may affect our business, financial condition, results of operation and cash flows. If one or more of these risks or uncertainties materialize, or if the underlying assumptions prove incorrect, our actual results may vary materially from those expected or projected.

Overview of PostRock

     PostRock Energy Corporation (“PostRock”) is a Delaware corporation formed on July 1, 2009 solely for the purpose of effecting a recombination of Quest Resource Corporation (now named PostRock Energy Services Corporation) (“QRCP”), Quest Energy Partners, L.P. (now named PostRock MidContinent Production, LLC) (“QELP”) and Quest Midstream Partners, L.P. (now named PostRock Midstream, LLC) (“QMLP”). Prior to the consummation of the recombination on March 5, 2010, we did not conduct any business operations other than incidental to our formation and in connection with the transactions contemplated by the merger agreement for the recombination. Following the recombination, we own QRCP, QELP and QMLP as direct or indirect wholly-owned subsidiaries and have no significant assets other than the stock and other voting securities of our subsidiaries.

     We are an integrated independent energy company involved in the acquisition, development, exploration, production and transportation of natural gas, primarily from coal seams (coal bed methane, or “CBM”) and unconventional shale, and oil and natural gas from conventional reservoirs. We conduct our business through two reportable business segments:

	•		Oil and natural gas production, and
	•		Natural gas pipelines, including transporting, gathering, treating and processing natural gas.

     Our principal operations and producing properties are located in the Cherokee Basin of southeastern Kansas and northeastern Oklahoma; Central Oklahoma; and West Virginia, Pennsylvania and New York in the Appalachian Basin. Our primary assets, as of March 31, 2010, consisted of natural gas wells, oil wells, development rights and natural gas gathering pipelines in the Cherokee Basin and Appalachian Basin, oil and natural gas wells and development rights in Central Oklahoma, and an interstate natural gas pipeline that transports natural gas from northern Oklahoma and western Kansas to the metropolitan Wichita and Kansas City markets.

     Unless the context requires otherwise, references to “we,” “us” and “our” are intended to mean and include the consolidated businesses and operations of QRCP and its subsidiaries (our “Predecessor”), including QELP and QMLP and their respective subsidiaries, for dates prior to March 6, 2010 and to the consolidated businesses and operations of PostRock and its subsidiaries (the “Successor”) for dates on or subsequent to March 6, 2010.

     Our highlights for the first quarter of 2010 include:

	•		Successfully completed the recombination of QRCP, QELP and QMLP.
	•		Completed and connected approximately 40 wells out of 108 previously drilled wells in the Cherokee Basin.
	•		Drilled three vertical wells in Appalachia allowing us to retain valuable acreage.
	•		Commenced initial production on our first vertical well drilled in Appalachia with initial production of approximately 1,800 Mcf/day.
	•		Decreased debt by $1.5 million.
	•		Generated cash flows from operations of $13.2 million.

Results of Operations

     The following discussion of financial condition and results of operations should be read in conjunction with the condensed consolidated financial statements and the related notes, which are included elsewhere in this report. Our results of operations for the three months ended March 31, 2010 represent the combined results of our Predecessor and PostRock. The results of operations for the three months ended March 31, 2009 are those of our Predecessor.

     In our Quarterly Report on Form 10-Q for the quarter ended March 31, 2009, we overstated the intercompany transportation revenue related to our natural gas pipeline segment and the corresponding intercompany transportation expense related to our oil and gas production segment by $2.2 million. As a result, our measure of segment profitability related to the natural gas pipeline segment was overstated by $2.2 million while segment profitability related to the oil and natural gas production segment was understated by the same amount. The error did not affect consolidated total revenues or net income for the period. Our disclosures herein reflect our correction of the misstatement discussed above.

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

		Three Months Ended
		March 31,								Increase/
		2010 (1)				2009				(Decrease)
Revenues:
Oil and gas sales		$	27,130			$	22,275			$	4,855				21.8	%
Natural gas pipelines			11,896				18,086				(6,190	)			(34.2	)%
Elimination of inter-segment revenue			(7,714	)			(10,283	)			2,569				25.0	%
Natural gas pipelines, net of inter-segment revenue			4,182				7,803				(3,621	)			(46.4	)%
Total segment revenues		$	31,312			$	30,078			$	1,234				4.1	%
Operating profit (loss):
Oil and gas production (2)		$	7,924			$	(110,749	)		$	118,673				107.2	%
Natural gas pipelines			3,611				6,959				(3,348	)			(48.1	)%
Total segment operating profit (loss)			11,535				(103,790	)			115,325				111.1	%
General and administrative expenses			(8,889	)			(7,882	)			(1,007	)			(12.8	)%
Total operating income (loss)		$	2,646			$	(111,672	)		$	114,318				102.4	%

     Three Months Ended March 31, 2010 Compared to the Three Months Ended March 31, 2009

Oil and Gas Production Segment

     Oil and gas production segment data for the periods indicated are as follows (in thousands, except unit and per unit data):

		Three Months Ended
		March 31,								Increase/
		2010 (1)				2009				(Decrease)
Oil and gas sales		$	27,130			$	22,275			$	4,855				21.8	%
Oil and gas production costs		$	7,771			$	7,686			$	85				1.1	%
Transportation expense (intercompany)		$	7,714			$	10,283			$	(2,569	)			(25.0	)%
Depreciation, depletion and amortization		$	3,721			$	12,153			$	(8,432	)			(69.4	)%
Production Data:
Natural gas production (Mmcf)			4,721				5,417				(696	)			(12.8	)%
Oil production (Mbbl)			18				20				(2	)			(10.0	)%
Total production (Mmcfe)			4,829				5,537				(708	)			(12.8	)%
Average daily production (Mmcfe/d)			53.7				61.5				(7.8	)			(12.7	)%

		Three Months Ended
		March 31,								Increase/
		2010				2009				(Decrease)
Average Sales Price per Unit:
Natural gas (Mcf)		$	5.46			$	3.83			$	1.63				42.6	%
Oil (Bbl)		$	74.85			$	75.05			$	(0.20	)			(0.3	)%
Natural gas equivalent (Mcfe)		$	5.62			$	4.02			$	1.60				39.8	%
Average Unit Costs per Mcfe:
Production costs		$	1.61			$	1.39			$	0.22				15.8	%
Transportation expense (intercompany)		$	1.60			$	1.86			$	(0.26	)			(14.0	)%
Depreciation, depletion and amortization		$	0.77			$	2.19			$	(1.42	)			(64.8	)%

     Oil and Gas Sales. Oil and gas sales increased $4.9 million, or 21.8%, to $27.1 million during the three months ended March 31, 2010 from $22.3 million during the three months ended March 31, 2009. This increase was primarily due to an increase in average realized natural gas prices which resulted in increased revenues of $8.9

million, partially offset by lower production volumes, which decreased revenue by $4.0 million. Natural gas equivalent volumes declined to 4.8 Bcfe for the three months ended March 31, 2010, or 12.8%, from 5.5 Bcfe for the three months ended March 31, 2009. Prices increased due to favorable market conditions. Production decreased primarily due to a lack of development activity beginning in the latter part of 2008 through 2009 as we faced liquidity constraints. Our lack of development activity has resulted in a limited number of new wells coming online, causing us to rely on existing wells to sustain production. These wells have been subject to a natural decline in production. Our average realized prices on an equivalent basis (Mcfe) increased to $5.62 per Mcfe for the three months ended March 31, 2010, from $4.02 per Mcfe for the three months ended March 31, 2009.

     Oil and Gas Operating Expenses. Oil and gas operating expenses consist of oil and gas production costs and transportation expense. Oil and gas operating expenses decreased $2.5 million, or 13.8%, to $15.5 million for the three months ended March 31, 2010, from $18.0 million for the three months ended March 31, 2009.

     Oil and gas production costs, which include lease operating expenses, severance taxes and ad valorem taxes, increased $0.1 million, or 1.1%, to $7.8 million during the three months ended March 31, 2010, from $7.7 million during the three months ended March 31, 2009. The increase was primarily due to higher ad valorem taxes of $1.2 million partially offset by a $1.1 million reduction in lease operating expense. Production costs were $1.61 per Mcfe for the three months ended March 31, 2010 as compared to $1.39 per Mcfe for the three months ended March 31, 2009.

     Transportation expense decreased $2.6 million, or 25.0%, to $7.7 million during the three months ended March 31, 2010, from $10.3 million during the three months ended March 31, 2009. The decrease was primarily due to a decrease in the contracted transportation fee. Transportation expense was $1.60 per Mcfe for the three months ended March 31, 2010 as compared to $1.86 per Mcfe for the three months ended March 31, 2009.

     Depreciation, Depletion and Amortization. We are subject to variances in our depletion rates from period to period due to changes in our oil and natural gas reserve quantities, production levels, product prices and changes in the depletable cost basis of our oil and natural gas properties. Our depreciation, depletion and amortization decreased approximately $8.4 million, or 69.4%, during the three months ended March 31, 2010 to $3.7 million from $12.2 million during the three months ended March 31, 2009. On a per unit basis, we had a decrease of $1.42 per Mcfe to $0.77 per Mcfe during the three months ended March 31, 2010 from $2.19 per Mcfe during the three months ended March 31, 2009. This decrease was primarily due to the impairment of our oil and gas properties in the first quarter of 2009 along with the impact to our reserves from higher prices in 2010, both of which decreased our rate per unit in the current quarter compared to the prior year quarter.

Natural Gas Pipelines Segment

     Natural gas pipelines segment data for the periods indicated are as follows (in thousands, except unit and per unit data):

		Three Months Ended
		March 31,
		2010 (1)				2009				Increase/ (Decrease)
Natural Gas Pipeline Revenue:
Gas pipeline revenue — Third Party		$	4,182			$	7,803			$	(3,621	)			(46.4	)%
Gas pipeline revenue — Intercompany			7,714				10,283				(2,569	)			(25.0	)%
Total natural gas pipeline revenue		$	11,896			$	18,086			$	(6,190	)			(34.2	)%
Pipeline operating expense		$	6,739			$	7,160			$	(421	)			(5.9	)%
Depreciation and amortization expense		$	1,546			$	3,967			$	(2,421	)			(61.0	)%
Throughput Data (Mmcf):
Throughput — Third Party			2,366				4,389				(2,023	)			(46.1	)%
Throughput — Intercompany			5,429				6,420				(991	)			(15.4	)%
Total throughput (Mmcf)			7,795				10,809				(3,014	)			(27.9	)%