UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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, 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		Smaller reporting company þ
				(Do not check if a smaller reporting company)

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

     At May 1, 2011, there were 8,290,482 outstanding shares of the registrant’s common stock having an aggregate market value of $63.2 million based on a closing price of $7.62 per share.

 

 

POSTROCK ENERGY CORPORATION
FORM 10-Q
FOR THE QUARTER ENDED MARCH 31, 2011

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 Stockholders’ Equity			F-4
Notes to 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			8
Item 4. Controls and Procedures			9
PART II — OTHER INFORMATION
Item 1. Legal Proceedings			10
Item 1A. Risk Factors			10
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			10
Item 3. Defaults Upon Senior Securities			10
Item 5. Other Information			10
Item 6. Exhibits			11
SIGNATURES			13
EX-10.1
EX-10.2
EX-31.1
EX-31.2
EX-32.1
EX-32.2

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

POSTROCK ENERGY CORPORATION

		December 31, 2010				March 31, 2011
						(Unaudited)
ASSETS
Current assets
Cash and equivalents		$	730			$	11
Accounts receivable — trade, net			11,845				10,494
Other receivables			1,153				994
Inventory			6,161				5,817
Other assets			2,799				3,960
Derivative financial instruments			31,588				29,588
Total			54,276				50,864
Oil and gas properties, full cost accounting, net			116,488				118,451
Pipeline assets, net			61,148				60,843
Other property and equipment, net			15,964				14,946
Other, net			9,303				10,306
Derivative financial instruments			39,633				32,474
Total assets		$	296,812			$	287,884
LIABILITIES AND EQUITY
Current liabilities
Accounts payable		$	7,030			$	8,583
Revenue payable			5,898				5,123
Accrued expenses			7,190				6,761
Litigation reserve			1,020				10,520
Current portion of long-term debt			10,500				12,000
Derivative financial instruments			3,792				4,705
Total			35,430				47,692
Derivative financial instruments			6,681				6,666
Long-term debt			209,721				191,923
Asset retirement obligations			7,150				7,334
Total liabilities			258,982				253,615
Commitments and contingencies
Series A Cumulative Redeemable Preferred Stock, $0.01 par value; issued and outstanding — 6,000 shares			50,622				52,091
Stockholders’ equity
Preferred stock, $0.01 par value; authorized shares — 5,000,000; 195,842 and 198,752 Series B Voting Preferred Stock issued and outstanding at December 31, 2010 and March 31, 2011, respectively			2				2
Common stock, $0.01 par value; authorized shares — 40,000,000; 8,238,982 and 8,290,482 issued and outstanding at December 31, 2010 and March 31, 2011, respectively			82				83
Additional paid-in capital			377,538				376,368
Accumulated deficit			(390,414	)			(394,275	)
Total deficit			(12,792	)			(17,822	)
Total liabilities and equity		$	296,812			$	287,884

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

POSTROCK ENERGY CORPORATION

		(Predecessors)
		January 1, 2010 to				March 6, 2010 to				Three Months Ended
		March 5, 2010				March 31, 2010				March 31, 2011
Revenues
Oil and gas sales		$	18,659			$	8,471			$	20,237
Gathering			1,076				430				1,356
Pipeline			1,749				927				3,173
Total			21,484				9,828				24,766
Costs and expenses
Production expense			8,645				4,118				12,434
Pipeline expense			1,110				637				1,660
General and administrative			5,735				1,584				4,888
Litigation reserve			—				1,570				9,500
Depreciation, depletion and amortization			4,164				1,103				6,891
(Gain) loss on sale of assets			—				172				(9,922	)
Total			19,654				9,184				25,451
Operating income			1,830				644				(685	)
Other income (expense)
Gain (loss) from derivative financial instruments			25,246				18,573				(821	)
Other income (expense), net			(4	)			(109	)			334
Interest expense, net			(5,336	)			(2,098	)			(2,689	)
Total other income (expense)			19,906				16,366				(3,176	)
Income before income taxes and non-controlling interests			21,736				17,010				(3,861	)
Income taxes			—				—				—
Net income			21,736				17,010				(3,861	)
Net income attributable to non-controlling interest			(9,958	)			—				—
Net income attributable to controlling interest			11,778				17,010				(3,861	)
Preferred dividends			—				—				(1,859	)
Accretion of redeemable preferred stock			—				—				(355	)
Net income (loss) available to common stock		$	11,778			$	17,010			$	(6,075	)
Net income (loss) per common share
Basic		$	0.37			$	2.12			$	(0.74	)
Diluted		$	0.36			$	2.04			$	(0.74	)
Weighted average common shares outstanding
Basic			32,137				8,038				8,256
Diluted			32,614				8,348				8,256

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

POSTROCK ENERGY CORPORATION

		(Predecessors)
		January 1, 2010 to				March 6, 2010 to				Three Months Ended
		March 5, 2010				March 31, 2010				March 31, 2011
Cash flows from operating activities
Net income (loss)		$	21,736			$	17,010			$	(3,861	)
Adjustments to reconcile net income to cash provided by operations:
Depreciation, depletion and amortization			4,164				1,103				6,891
Stock-based compensation			808				83				299
Amortization of deferred loan costs			2,094				396				421
Change in fair value of derivative financial instruments			(21,573	)			(15,439	)			10,057
Litigation reserve			—				1,450				9,500
Loss (gain) on disposal of property and equipment			—				172				(9,922	)
Other non-cash changes to net income			—				111				(291	)
Change in assets and liabilities
Receivables			777				481				1,535
Payables			743				1,460				187
Other			468				(2,553	)			(2,227	)
Cash flows from operating activities			9,217				4,274				12,589
Cash flows from investing activities
Restricted cash			(1	)			155				28
Proceeds from sale of oil and gas properties			—				—				5,763
Equipment, development, leasehold and pipeline			(2,282	)			(2,241	)			(8,530	)
Cash flows from investing activities			(2,283	)			(2,086	)			(2,739	)
Cash flows from financing activities
Proceeds from debt			900				500				—
Repayments of debt			(41	)			(4,004	)			(10,569	)
Cash flows from financing activities			859				(3,504	)			(10,569	)
Net increase (decrease) in cash			7,793				(1,316	)			(719	)
Cash and equivalents–beginning of period			20,884				28,677				730
Cash and equivalents–end of period		$	28,677			$	27,361			$	11

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

POSTROCK ENERGY CORPORATION

						Preferred				Common				Common				Additional								Total
		Preferred				Stock				Shares				Stock				Paid-in				Accumulated				(Deficit)
		Shares				Par Value				Issued				Par Value				Capital				Deficit				Equity
Balance, December 31, 2010			195,842			$	2				8,238,982			$	82			$	377,538			$	(390,414	)		$	(12,792	)
Stock-based compensation			—				—				—				—				299				—				299
Restricted stock grants, net of forfeitures			—				—				51,500				1				—				—				1
Issuance of Series B preferred stock			2,910				—				—				—				—				—				—
Issuance of warrants			—				—				—				—				745				—				745
Preferred stock dividends			—				—				—				—				(1,859	)			—				(1,859	)
Preferred stock accretion			—				—				—				—				(355	)			—				(355	)
Net income			—				—				—				—				—				(3,861	)			(3,861	)
Balance, March 31, 2011			198,752			$	2				8,290,482			$	83			$	376,368			$	(394,275	)		$	(17,822	)

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

POSTROCK ENERGY CORPORATION

Note 1 — Basis of Presentation

     PostRock Energy Corporation (“PostRock”) is an independent oil and gas company engaged in the acquisition, exploration, development, production and gathering of crude oil and natural gas. It manages its business in two segments, production and pipeline. Its production segment is focused in the Cherokee Basin, a 15-county region in southeastern Kansas and northeastern Oklahoma. It also has minor oil producing properties in Oklahoma and gas producing properties in the Appalachia Basin. The pipeline segment consists of a 1,120 mile interstate natural gas pipeline, which transports natural gas from northern Oklahoma and western Kansas to Wichita and Kansas City.

     PostRock was formed in 2009 to combine its predecessor entities, Quest Resource Corporation, Quest Energy Partners, L.P. and Quest Midstream Partners, L.P. (collectively, the “Predecessors”) into a single company. In March 2010, it completed the recombination of these entities. Unless the context requires otherwise, references to the “Company,” “we,” “us” and “our” refer to PostRock and its subsidiaries from the date of the recombination and to the Predecessors on a consolidated basis prior thereto.

     The unaudited interim condensed consolidated financial statements have been prepared by the Company 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, 2010 (the “2010 10-K”).

     The preparation of 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 consolidated 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.

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 (“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 is 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. The provisions requiring gross

presentation of activity within Level 3 assets were adopted in the current quarter. Other than additional disclosure required by the update, there was no material impact on its financial statements.

Note 2 — Divestitures

     Appalachia Basin Sale — On December 24, 2010, the Company entered into an agreement with Magnum Hunter Resources Corporation (“MHR”) to sell certain oil and gas properties and related assets in Wetzel and Lewis Counties, West Virginia. The sale closed in two phases for a total of $39.7 million. The first phase closed on December 30, 2010, for $28 million. The second closed on January 14, 2011, for $11.7 million. The amount received at both closings was paid half in cash and half in MHR common stock. The agreement contained provisions for a third closing if certain conditions are met before May 15, 2011. That deadline was subsequently extended to June 15, 2011. There can be no assurance that the third closing will occur.

     In general, no gains or losses are recognized upon the sale or disposition of oil and gas properties unless the deferral of gains or losses would significantly alter the relationship between capitalized costs and proved reserves of oil and gas. A significant alteration generally occurs when the deferral of gains or losses will result in an amortization rate materially different from the amortization rate calculated upon recognition of gains or losses. The Company’s evaluation demonstrated that a material difference in amortization rates would occur if no gain was recognized on the sale described above and therefore recorded a gain of $10.0 million, net of $114,000 in selling costs, in January 2011 related to the second phase of the sale with a corresponding reduction in the carrying amount of its oil and gas full cost pool of $1.5 million. During the first quarter of 2011, the Company reduced the gain on the Appalachia Basin sale by $111,000 to reflect post-closing adjustments pursuant to the sale agreement with MHR.

Note 3 — 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. 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. Specifically, the Company may utilize futures, swaps and options.

     Derivative instruments expose the Company to counterparty credit risk. The Company’s commodity derivative instruments are currently with several counterparties. The Company generally executes commodity derivative instruments under master agreements which allow it, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If the Company chooses to elect early termination, all asset and liability positions with the defaulting counterparty would be net cash settled at the time of election.

     The Company monitors the creditworthiness of its counterparties; however, it is not able to predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, it may be limited in its ability to mitigate an increase in counterparty credit risk. Possible actions would be to transfer its position to another counterparty or request a voluntary termination of the derivative contracts resulting in a cash settlement. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments under lower commodity prices as well as incur a loss. The Company includes a measure of counterparty credit risk in its estimates of the fair values of derivative instruments in an asset position.

     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. The table below outlines the classification of derivative financial instruments on the condensed consolidated balance sheet and their financial impact on the condensed consolidated statements of operations at and for the periods indicated (in thousands):

				December 31,				March 31,
Derivative Financial Instruments		Balance Sheet location		2010				2011
Commodity contracts		Current derivative financial instrument asset		$	31,588			$	29,588
Commodity contracts		Long-term derivative financial instrument asset			39,633				32,474
Commodity contracts		Current derivative financial instrument liability			(3,792	)			(4,705	)
Commodity contracts		Long-term derivative financial instrument liability			(6,681)				(6,666	)
				$	60,748			$	50,691

     Gains and losses associated with derivative financial instruments related to oil and gas production were as follows for the periods indicated (in thousands):

		(Predecessors)
		January 1, 2010 to				March 6, 2010 to				Three Months Ended
		March 5, 2010				March 31, 2010				March 31, 2011
Realized gains		$	3,673			$	3,134			$	9,236
Unrealized gains (losses)			21,573				15,439				(10,057	)
Total		$	25,246			$	18,573			$	(821	)

     The following table summarizes the estimated volumes, fixed prices and fair values attributable to all of the Company’s oil and gas derivative contracts at March 31, 2011.

		Remainder of				Year Ending December 31,
		2011				2012				2013				Total
		($ in thousands, except per unit data)
Natural Gas Swaps
Contract volumes (Mmbtu)			10,202,283				11,000,004				9,000,003				30,202,290
Weighted-average fixed price per Mmbtu		$	6.70			$	7.13			$	7.28			$	7.03
Fair value, net		$	22,613			$	23,122			$	16,327			$	62,062
Natural Gas Basis Swaps
Contract volumes (Mmbtu)			6,441,780				9,000,000				9,000,003				24,441,783
Weighted-average fixed price per Mmbtu		$	(0.69	)		$	(0.70	)		$	(0.71	)		$	(0.70	)
Fair value, net		$	(2,850	)		$	(3,554	)		$	(3,411	)		$	(9,815	)
Crude Oil Swaps
Contract volumes (Bbl)			36,000				42,000				—				78,000
Weighted-average fixed price per Bbl		$	85.90			$	87.90			$	—			$	86.98
Fair value, net		$	(792	)		$	(764	)		$	—			$	(1,556	)
Total fair value, net		$	18,971			$	18,804			$	12,916			$	50,691

     The following table summarizes the estimated volumes, fixed prices and fair values attributable to all of the Company’s oil and gas derivative contracts at December 31, 2010:

		Year Ending December 31,
		2011				2012				2013				Total
		($ in thousands, except per unit data)
Natural Gas Swaps
Contract volumes (Mmbtu)			13,550,302				11,000,004				9,000,003				33,550,309
Weighted-average fixed price per Mmbtu		$	6.80			$	7.13			$	7.28			$	7.04
Fair value, net		$	31,588			$	22,728			$	16,905			$	71,221
Natural Gas Basis Swaps
Contract volumes (Mmbtu)			8,549,998				9,000,000				9,000,003				26,550,001
Weighted-average fixed price per Mmbtu		$	(0.67	)		$	(0.70	)		$	(0.71	)		$	(0.69	)
Fair value, net		$	(3,417	)		$	(3,405	)		$	(3,031	)		$	(9,853	)
Crude Oil Swaps
Contract volumes (Bbl)			48,000				42,000				—				90,000
Weighted-average fixed price per Bbl		$	85.90			$	87.90			$	—			$	86.83
Fair value, net		$	(375	)		$	(245	)		$	—			$	(620	)
Total fair value, net		$	27,796			$	19,078			$	13,874			$	60,748

Note 4 — Fair Value Measurements

     Certain assets and liabilities are measured at fair value on a recurring basis in the Company’s condensed consolidated balance sheets. The following methods and assumptions were used to estimate the fair values:

     Cash and Equivalents, Accounts Receivable and Accounts Payable The carrying amounts approximate fair value due to the short-term nature or maturity of the instruments.

     Commodity Derivative Instruments The Company’s oil and gas derivative instruments may consist of variable to fixed price swaps, collars and basis swaps. When possible, the Company estimates the fair values of these instruments based on published forward commodity price curves as of the date of the estimate. The discount rate used in the discounted cash flow projections is based on published LIBOR rates adjusted for counterparty credit risk. Counterparty credit risk is incorporated into derivative assets while the Company’s own credit risk is incorporated into derivative liabilities. Both are based on the current published credit default swap rates. See Note 3. Derivative Instruments and Hedging Activities.

     Short-Term Investments Short term investments are included in other current assets in the condensed consolidated balance sheet. At March 31, 2011, these investments consisted of common stock of MHR received as proceeds from the sale of certain Appalachia oil and gas assets, discussed previously. The fair value of these securities is based on the published market price of the common stock adjusted for the remaining three to four month restrictions on the Company’s ability to trade the securities.

     Measurement information for assets and liabilities that are measured at fair value on a recurring basis was as follows:

														Total Net Fair
		Level 1				Level 2				Level 3				Value
At December 31, 2010
Short term investments — other current assets		$	—			$	1,354			$	—			$	1,354
Derivative financial instruments — assets			—				71,221				—				71,221
Derivative financial instruments — liabilities			—				(620	)			(9,853	)			(10,473	)
Total		$	—			$	71,955			$	(9,853	)		$	62,102
At March 31, 2011
Short term investments — other current assets		$	—			$	1,817			$	—			$	1,817
Derivative financial instruments — assets			—				62,062				—				62,062
Derivative financial instruments — liabilities			—				(1,556	)			(9,815	)			(11,371	)
Total		$	—			$	62,323			$	(9,815	)		$	52,508

Level 1 — Quoted prices available in active markets for identical assets or liabilities at 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 at 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.

     There were no movements between Levels 1 and 2 during the periods from January 1 to March 5 and March 6 to March 31, 2010, and during the three months ended March 31, 2011.

     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 for the periods presented (in thousands). There were no transfers into and out of Level 3, purchases, sales or issuances during the time period presented.

		Predecessors
		January 1, 2010 to				March 6, 2010 to				Three Months Ended
		March 5, 2010				March 31, 2010				March 31, 2011
Balance at beginning of period		$	1,530			$	5,455			$	(9,853	)
Realized and unrealized gains included in earnings			7,254				11,275				(857	)
Settlements			(3,329	)			(2,761	)			895
Balance at end of period		$	5,455			$	13,969			$	(9,815	)

     Additional Fair Value Disclosures — The Company has 6,000 outstanding shares of Series A Cumulative Redeemable Preferred Stock (see Note 7 — Redeemable Preferred Stock and Warrants). The fair value and the carrying value of these securities were $68.5 million and $50.6 million, respectively, at December 31, 2010, and $65.2 million and $52.1 million, respectively, at March 31, 2011. The fair value was determined by discounting the cash flows over the remaining life of the securities utilizing a LIBOR interest rate and a risk premium of approximately 6.9% and 8.4% at December 31, 2010, and March 31, 2011, respectively, which was based on companies with similar leverage ratios to PostRock.

     The Company’s long term debt consists entirely of floating-rate facilities. The carrying amount of floating-rate debt approximates fair value because the interest rates paid on such debt are generally set for periods of six months or shorter.

Note 5 — Asset Retirement Obligations

     The following table reflects the changes to the Company’s asset retirement obligations for the period indicated (in thousands):

		Predecessors
		January 1, 2010 to				March 6, 2010 to				Three Months Ended
		March 5, 2010				March 31, 2010				March 31, 2011
Asset retirement obligations at beginning of period		$	6,552			$	6,648			$	7,150
Liabilities incurred			—				1				23
Liabilities settled			(1	)			(4	)			—
Accretion			97				42				161
Divestitures			—				—				—
Asset retirement obligations at end of period		$	6,648			$	6,687			$	7,334

Note 6 — Long-Term Debt

     The following is a summary of PostRock’s long-term debt at the dates indicated (in thousands):

		December 31,				March 31,
		2010				2011
Borrowing Base Facility		$	187,000			$	181,500
Secured Pipeline Loan			13,500				12,000
QER Loan			19,721				10,423
Total debt			220,221				203,923
Less current maturities included in current liabilities			10,500				12,000
Total long-term debt		$	209,721			$	191,923

     The terms of the Company’s credit facilities are described within Note 10 of Item 8. Financial Statement and Supplementary Data in the 2010 10-K.

     As discussed in Note 2, the Company sold certain Appalachia Basin oil and gas properties to MHR in December 2010 and January 2011. The Company received total consideration of $11.7 million for the second closing in January 2011 consisting of $5.8 million in cash and 0.9 million shares of MHR common stock with a fair value of $5.9 million. Of the cash amount, $1.7 million was placed in escrow. Included in the $39.7 million aggregate purchase price for both closings was approximately $36.7 million representing the purchase price of assets owned by one of the Company’s subsidiaries, Quest Eastern Resources (“QER”), pledged as collateral under the QER Loan. Approximately $12.1 million of the net cash consideration and the share consideration received by QER pursuant to the purchase agreement (totaling 3.0 million shares) were paid to the lender, Royal Bank of Canada (“RBC”), in repayment of the QER Loan and as consideration for the release of RBC’s liens encumbering the assets sold, which resulted in payments to RBC of $21.2 million in December 2010 and $9.3 million in January 2011 from the first and second phases of the asset sale. The $9.3 million payment on January 2011 consisted of $5.7 million in MHR stock and $3.6 million in cash.

     In addition to the payments described above, the Company made periodic payments of $1.5 million on the Secured Pipeline Loan and net payments of $5.5 million on the Borrowing Base Facility during the first quarter of 2011. The Company was in compliance with all its financial covenants at March 31, 2011.

Note 7 — Redeemable Preferred Stock and Warrants

     On March 31, 2011, the Company elected to not pay cash dividends of $1.9 million accrued for the quarter ended March 31, 2011, on its Series A Preferred Stock. Accordingly the liquidation preference of the Series A Preferred Stock increased by the same amount and the Company issued additional warrants to purchase 290,986 shares of

PostRock common stock at a strike price of $6.39 and 2,910 additional shares of Series B Preferred Stock. The Company recorded the increase in liquidation preference and the issuance of additional warrants by allocating their relative fair values to the $1.9 million amount of accrued dividends. The allocation resulted in an increase to the Company’s temporary equity of $1.1 million related to the Series A Preferred Stock and an increase to additional paid in capital of $745,000 related to the additional warrants issued.

     The following tables describe the changes in temporary equity, currently comprised of the Series A Preferred Stock (in thousands except share amounts), and in outstanding warrants:

						Number of
		Series A Preferred				Outstanding
		Stock				Shares				Liquidation Value
Balance on December 31, 2010		$	50,622				6,000			$	61,980
Dividends paid in kind			1,114				—				1,859
Accretion			355				—				—
Balance on March 31, 2011		$	52,091				6,000			$	63,839

		Outstanding				Weighted Average
		Warrants				Exercise Price
Balance on December 31, 2010			19,584,205			$	3.16
Dividends paid in kind			290,986			$	6.39
Balance on March 31, 2011			19,875,191			$	3.21

Note 8 — Equity and Earnings per Share

     Share-Based Payments — During the first quarter of 2011, the Company granted 51,500 restricted share awards that vest in one year, 18,900 stock options to employees that vest ratably over a three year period and 10,000 stock options to directors that vested immediately. The employee stock options had an exercise price of $6.15 and were valued utilizing a volatility of 74.7% and a risk free rate of 2.00%. The director stock options had an exercise price of $4.80 and were valued utilizing a volatility of 77.0% and a risk free rate of 1.93%. The grant date fair values were $6.15 per restricted share, $3.79 per employee stock option and $3.02 per director stock option. The Company recorded share based compensation expense of $808,000 and $83,000 for the periods from January 1 to March 5 and March 6 to March 31, 2010, respectively, and $299,000 for the three months ended March 31, 2011. Total share-based compensation to be recognized on unvested stock awards and options at March 31, 2011, is $2.0 million over a weighted average period of 1.41 years.

     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 per share amounts):

		(Predecessors)
		January 1, 2010 to				March 6, 2010 to				Three Months Ended
		March 5, 2010				March 31, 2010				March 31, 2011
Net income (loss) attributable to controlling interests		$	11,778			$	17,010			$	(3,861	)
Preferred accretion			—				—				(355	)
Preferred stock dividends			—				—				(1,859	)
Net income (loss) attributable to common stockholders		$	11,778			$	17,010			$	(6,075	)
Denominator
Common shares			32,016,327				8,038,974				8,256,149
Weighted average number of unvested share-based awards participating			121,121				—				—
Denominator for basic earnings per share			32,137,448				8,038,974				8,256,149
Effect of potentially dilutive securities
Unvested share-based awards non-participating			450,751				308,093				—
Stock options			26,154				1,423				—
Denominator for diluted earnings per share			32,614,353				8,348,490				8,256,149
Basic earnings per share		$	0.37			$	2.12			$	(0.74	)
Diluted earnings per share		$	0.36			$	2.04			$	(0.74	)
Securities excluded from earnings per share calculation:
Unvested share-based awards			—				—				392,000
Antidilutive stock options			570,000				32,775				536,350
Warrants			—				—				19,875,191

Note 9 — 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. It records a liability related to its legal proceedings and claims when it has determined that it is probable that it will be obligated to pay and the related amount can be reasonably estimated. Except for those legal proceedings listed below, it believes there are no pending legal proceedings in which it is currently involved which, if adversely determined, could have a material adverse effect on its financial position, results of operations or cash flow.

     As further described in Note 14 of Part II, Item 8 in the 2010 10-K, the Company has been sued in three lawsuits filed by royalty owners. Two of these actions have been filed in the District Court of Nowata County, State of Oklahoma, and one has been filed in the U.S. District Court for the District of Kansas.

     The lawsuit in Kansas is a putative class action, consisting of all royalty owners in the Kansas portion of the Cherokee Basin. Plaintiffs allege 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. No class certification hearing has yet been scheduled. The parties have participated in multiple mediation sessions with the most recent in January 2011 and continue to engage in settlement discussions. The parties have agreed to a period of limited discovery with another mediation to occur thereafter. If the matter cannot be resolved at that time the case will proceed with general discovery, a class certification hearing, and a trial on the merits.

     In Oklahoma, the two suits have been consolidated to proceed as a single action. Plaintiffs are royalty interest owners located in Nowata and Craig counties who allege that the Company has wrongfully deducted post-production costs from the plaintiffs’ royalties and have engaged in self-dealing contracts and agreements resulting in a less than market price for the gas production. Plaintiffs seek unspecified actual and punitive damages. Discovery is currently ongoing. The parties participated in mediations on February 25 and March 9, 2011, and continue to engage in settlement discussions.

     The Company has reserved $10.5 million for the estimated potential cost to resolve the royalty owner lawsuits pending in Oklahoma and Kansas, which includes $9.5 million added in the first quarter of 2011. There can be no assurance the amount accrued will be sufficient to cover any final settlement or damage awards. The Company is vigorously defending against these lawsuits.

     Contractual Commitments — The Company has numerous contractual commitments in the ordinary course of business, debt service requirements and operating lease commitments. During the first quarter of 2011, the Company entered into new operating leases for compressors utilized in its gathering system. The new leases were entered into on existing compressors that the Company had previously been leasing on a month-to-month basis. The new compressor leases resulted in an increase to the Company’s contractual commitments of approximately $900,000 in 2011 from the amount of its outstanding commitments as of December 31, 2010. Except for these leases and the debt repayments during the first quarter of 2011 described in Note 6, as of March 31, 2011, there were no other material changes to the Company’s commitments since December 31, 2010.

Note 10 — Operating Segments

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

		Production				Pipeline				Total
January 1, 2010 to March 5, 2010 (Predecessor)
Revenues		$	19,735			$	1,749			$	21,484
Operating profit		$	7,516			$	49			$	7,565
March 6, 2010 to March 31, 2010
Revenues		$	8,901			$	927			$	9,828
Operating profit		$	3,768			$	30			$	3,798
Three months ended March 31, 2011
Revenues		$	21,593			$	3,173			$	24,766
Operating profit		$	13,130			$	573			$	13,703
Identifiable assets
December 31, 2010		$	232,111			$	64,701			$	296,812
March 31, 2011		$	223,783			$	64,101			$	287,884

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

		Predecessors
		January 1, 2010 to				March 6, 2010 to				Three Months Ended
		March 5, 2010				_March 31, 2010				March 31, 2011
Segment operating profit (1)		$	7,565			$	3,798			$	13,703
General and administrative expenses			(5,735	)			(1,584	)			(4,888	)
Litigation reserve			—				(1,570	)			(9,500	)
Gain (loss) from derivative financial instruments			25,246				18,573				(821	)
Interest expense, net			(5,336	)			(2,098	)			(2,689	)
Other income (expense), net			(4	)			(109	)			334
Income before income taxes and noncontrolling interests		$	21,736			$	17,010			$	(3,861	)

Note 11 — Subsequent Events

     The Company evaluated its activity from March 31, 2011, until the date of issuance for recognized and unrecognized subsequent events not discussed elsewhere in these footnotes and determined there were none.

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

Overview

     PostRock Energy Corporation (“PostRock”) is an independent oil and gas company engaged in the acquisition, exploration, development, production and gathering of crude oil and natural gas. We manage our business in two segments, production and pipeline. Our production segment is focused in the Cherokee Basin, a 15-county region in southeastern Kansas and northeastern Oklahoma. We also have minor oil producing properties in Oklahoma and gas producing properties in the Appalachia Basin. Our pipeline segment consists of a 1,120 mile interstate natural gas pipeline, which transports natural gas from northern Oklahoma and western Kansas to Wichita and Kansas City.

     The following discussion should be read together with the unaudited consolidated financial statements and related notes included elsewhere herein and with our annual report on Form 10-K for the year ended December 31, 2010.

     Our highlights for the first quarter of 2011 include:

	•		Closed on the second phase of our Appalachia Basin sale for $11.7 million.
	•		Decreased debt by $16.3 million from December 31, 2010.
	•		Brought 56 new oil and gas wells online in the Cherokee Basin, of which 17 were drilled prior to 2011, and returned 30 wells in the basin to production.

2011 Drilling Program Update

      We have budgeted $43.6 million for our 2011 drilling program. During the first quarter of 2011, we drilled and connected 39 development wells, completed 9 new wells drilled in prior periods, recompleted or connected 20 wells and returned 30 wells to production in the Cherokee Basin. Additionally, we returned 30 wells that had been shut-in back to producing status. Though individual well results varied by area, production from the wells brought on-line during the first quarter is meeting cumulative production expectations. We have spent $8.2 million for drilling and completion through March 31, 2011, compared to $10.8 million budgeted. Capital spending is under budget due to extreme weather conditions that caused us to defer certain projects. We will continue to evaluate our drilling program in an effort to ensure all projects provide an attractive rate of return.

Results of Operations

     In March 2010, PostRock completed the recombination of its three predecessor entities. The results of operations for the three months ended March 31, 2010 represent the combined results of these predecessor entities and PostRock. The results of operations for the three months ended March 31, 2011 are those of PostRock. Unless the context requires otherwise, references to the “Company,” “we,” “us” and “our” refer to PostRock and its subsidiaries from the date of the recombination and to the three predecessor entities on a consolidated basis prior thereto. Operating segment data for the periods indicated are as follows (in thousands):

		Three Months Ended
		March 31,								Increase/
		2010				2011				(Decrease)
Revenues
Oil and gas sales		$	27,130			$	20,237			$	(6,893	)			(25.4	)%
Gathering			1,506				1,356				(150	)			(10.0	)%
Total production segment			28,636				21,593				(7,043	)			(24.6	)%
Pipeline segment			2,676				3,173				497				18.6	%
Total		$	31,312			$	24,766			$	(6,546	)			(20.9	)%
Operating profit
Production		$	11,284			$	13,130			$	1,846				16.4	%
Pipelines			79				573				494				625.3	%
Total segment operating profit			11,363				13,703				2,340				20.6	%
General and administrative expenses			(7,319	)			(4,888	)			2,431				33.2	%
Litigation reserve			(1,570	)			(9,500	)			(7,930	)			(505.1	)%
Total operating profit		$	2,474			$	(685	)		$	(3,159	)			(127.7	)%

Three Months Ended March 31, 2010 Compared to the Three Months Ended March 31, 2011

     The following table presents financial and operating data for the periods indicated as follows:

		Three Months Ended
		March 31,								Increase/
		2010				2011				(Decrease)
		($ in thousands except per unit data)
Production Segment
Oil and gas sales		$	27,130			$	20,237			$	(6,893	)			(25.4	)%
Gathering revenue		$	1,506			$	1,356			$	(150	)			(10.0	)%
Production operating costs		$	12,763			$	12,434			$	(329	)			(2.6	)%
Depreciation, depletion and amortization		$	4,417			$	5,951			$	1,534				34.7	%
Gain (loss) on sale of assets		$	(172	)		$	9,922			$	10,094				*	%
Production Data
Total production (Mmcfe)			4,829				4,673				(156	)			(3.2	)%
Average daily production (Mmcfe/d)			53.7				51.9				(1.8	)			(3.2	)%
Average Sales Price per Unit (Mcfe)
Natural Gas (Mcf)		$	5.46			$	4.08			$	(1.38	)			(25.3	)%
Oil(Bbl)		$	74.85			$	88.58			$	13.73				18.3	%
Natural Gas Equivalent (Mcfe)		$	5.62			$	4.33			$	(1.29	)			(22.9	)%
Average Unit Costs per Mcfe
Production operating costs		$	2.64			$	2.66			$	0.02				0.7	%
Depreciation, depletion and amortization		$	0.91			$	1.27			$	0.36				39.6	%
Pipeline Segment
Pipeline revenue		$	2,676			$	3,173			$	497				18.6	%
Pipeline operating expense		$	1,747			$	1,660			$	(87	)			(5.0	)%
Depreciation and amortization expense		$	850			$	940			$	90				10.6	%

     Oil and gas sales decreased $6.9 million, or 25.4%, from $27.1 million during the three months ended March 31, 2010 to $20.2 million during the three months ended March 31, 2011. Decreased average realized natural gas prices resulted in decreased revenues of $6.0 million and lower production volumes decreased revenue by $887,000. Production decreased primarily due to the divestiture of the Appalachia Basin assets and extreme weather in the Cherokee Basin during the first quarter of 2011, which deferred production to future periods. Our average realized prices on an equivalent basis (Mcfe) decreased from $5.62 per Mcfe for the three months ended March 31, 2010, to $4.33 per Mcfe for the three months ended March 31, 2011.

     Gathering revenue decreased $150,000, or 10.0%, from $1.5 million for the three months ended March 31, 2010 to $1.4 million for the three months ended March 31, 2011, primarily due to lower volumes.

     Pipeline revenue increased $497,000, or 18.6%, from $2.7 million for the three months ended March 31, 2010 to $3.2 million for the three months ended March 31, 2011. The increase was primarily due to higher volumes transported and additional short-term firm transportation contracts.

     Oil and gas production costs consist of lease operating expenses, severance and ad valorem taxes and gathering expense. Production costs decreased $329,000, or 2.6%, from $12.7 million for the three months ended March 31, 2010, to $12.4 million for the three months ended March 31, 2011. The decrease was primarily due to lower severance and ad valorem taxes of approximately $900,000 partially offset by an approximately $600,000 increase in lease operating expenses. Lease operating expenses were higher primarily due to a one-time well repair expense in the Company’s oil producing assets in Oklahoma. Production costs were $2.64 per Mcfe for the three months ended March 31, 2010 as compared to $2.66 per Mcfe for the three months ended March 31, 2011.

     Pipeline operating expense decreased $87,000, or 5.0%, from $1.7 million during the three months ended March 31, 2010, to $1.6 million during the three months ended March 31, 2011. While we had a significant reduction in costs related to our capacity lease that expires at the end of October 2011, the cost to replace line-pack lost to an external corrosion leak offset the reduction.

     Depreciation, depletion and amortization increased $1.6 million, or 30.8%, from $5.3 million during the three months ended March 31, 2010, to $6.9 million during the three months ended March 31, 2011. Depletion and amortization on our production properties increased approximately $1.5 million, or 34.7%, from $4.4 million during the three months ended March 31, 2010 to $5.9 million during the three months ended March 31, 2011. On a per unit basis, we had an increase of $0.36 per Mcfe from $0.91 per Mcfe during the three months ended March 31, 2010 to $1.27 per Mcfe during the three months ended March 31, 2011. The increase in depletion and amortization rate was the result of a change from the straight-line method of depreciation to the units-of production method upon reclassifying our gathering system to our production full cost pool in the fourth quarter of 2010. The gathering system was previously a component of our pipeline segment and depreciated under the straight line method. Depreciation and amortization expense on our pipeline segment increased $90,000, or 10.6%, from $850,000 during the three months ended March 31, 2010, to $940,000 during the three months ended March 31, 2011.

     Gain from the sale of assets of $9.9 million during the three months ended March 31, 2011, was primarily due to the second phase of the Appalachia Basin sale in January 2011.

     General and administrative expenses decreased $2.4 million, or 33%, from $7.3 million during the three months ended March 31, 2010, to $4.9 million during the three months ended March 31, 2011. The March 2010 recombination and the September 2010 recapitalization have enabled us to focus on reducing all areas of our back office costs and focus on running our business. Accounting, tax, audit and financial consultant fees decreased $1.6 million and legal fees decreased $0.9 million. Compensation and benefits increased $100,000 which was primarily the result of the settlement of a workers’ compensation audit from prior periods. We believe general and administrative expenses will remain consistent with the first quarter of 2011 for the remainder of 2011.

     Litigation reserve expense increased $7.9 million from $1.6 million during the three months ended March 31, 2010, to $9.5 million during the three months ended March 31, 2011. During the first quarter of 2011, we added $9.5 million to our litigation reserve, bringing the total reserve to $10.5 million. This amount is the estimated potential cost to resolve royalty owner lawsuits pending in Oklahoma and Kansas. These represent the last known significant contingent liability remaining from our predecessor entities. See Note 8 in Part I, Item 1 of this report for a discussion of the lawsuits. The first quarter of 2010 expense was primarily related to settling the various shareholder related lawsuits.

     Other income (expense) consists of gains from derivative instruments and net interest expense. Gain from derivative financial instruments decreased $44.6 million, or 101.9%, from a gain of $43.8 million for the three months ended March 31, 2010, to a loss of $821,000 for the three months ended March 31, 2011. We recorded a $37.0 million unrealized gain and $6.8 million realized gain on our derivative contracts for the three months ended March 31, 2010 compared to a $10.0 million unrealized loss and $9.2 million realized gain for the three months ended March 31, 2011. Interest expense, net, decreased $4.7 million, or 63.8%, from $7.4 million during the three months ended March 31, 2010, to $2.7 million during the three months ended March 31, 2011. The decrease is primarily due to a $2.1 million decrease in amortization of debt issuance costs and a $2.7 million decrease in interest charges on outstanding debt due to a reduced level of debt and lower interest rates resulting from the restructuring of our credit facilities in September 2010.

Liquidity and Capital Resources

     Cash flows from operating activities have historically been driven by the quantities of our production, the prices received from the sale of this production, and from our pipeline revenue. Prices of oil and gas have historically been very volatile and can significantly impact the cash from the sale our production. Use of derivative financial instruments help mitigate this price volatility. Cash expenses also impact our operating cash flow and consist

primarily of production operating costs, severance and ad valorem taxes, interest on our indebtedness and general and administrative expenses.

     Our primary sources of liquidity for the three months ended March 31, 2011 were cash generated from our operations, cash from the sale of oil and gas properties and available borrowings under our borrowing base credit facility. At March 31, 2011, including $11,000 in cash and $1.5 million in outstanding letters of credit, we had $42.0 million of availability under the facility.

     Cash Flows from Operating Activities Cash flows provided by operating activities were relatively flat, decreasing $902,000 from $13.5 million for the three months ended March 31, 2010, to $12.6 million for the three months ended March 31, 2011. The decrease was primarily the result of lower oil and gas sales.

     Cash Flows from Investing Activities Cash flows used in investing activities were $4.4 million for the three months ended March 31, 2010, compared to $2.7 million for the three months ended March 31, 2011. Capital expenditures were $4.5 million and $8.5 million for the three months ended March 31, 2010 and 2011, respectively. Cash proceeds from the second phase of our Appalachia Basin sale in the first quarter of 2011 were $5.8 million. The following table sets forth our capital expenditures, including costs we have incurred but not paid, by major categories for the three months ended March 31, 2011 (in thousands):

		Three Months Ended
		March 31, 2011
Capital expenditures
Leasehold acquisition		$	172
Development			8,275
Pipelines			147
Other items			263
Total capital expenditures		$	8,857

     Cash Flows from Financing Activities Cash flows used in financing activities totaled $2.6 million for the three months ended March 31, 2010 as compared to $10.6 million for the three months ended March 31, 2011. The cash used in financing activities during 2011 was for debt repayments. The cash used in financing activities during 2010 was for debt repayments of $4.0 million partially offset by borrowings of $1.4 million.

Sources of Liquidity in 2011 and Capital Requirements

     At April 30, 2011, we have $41.3 million of availability under our borrowing base credit facility, which we utilize as an external source of long and short term liquidity. An additional $30 million of capital may also be available from White Deer Energy for acquisitions, an accelerated development program or other corporate purposes on mutually acceptable terms pursuant to our securities purchase agreement with White Deer.

     Our borrowing base credit facility will undergo a borrowing base redetermination based on reserves as of March 31, 2011 that will be effective July 31, 2011. The borrowing base under that facility is determined based on the value of our oil and natural gas reserves at our lenders’ forward price forecasts, which are generally derived from futures prices. As such, our borrowing base can be adversely affected by downward fluctuations in future prices of oil and natural gas. There has been a significant decline in lender forward price forecasts since our borrowing base was last determined and as a result we expect a reduction in our borrowing base. A reduction in the borrowing base will reduce our available liquidity. If the reduction results in the outstanding amount under the facility exceeding the borrowing base, we will be required to repay the deficiency within 30 days or in six monthly installments thereafter at our election.

     On May 4, 2011, we filed a $100 million universal shelf registration statement on Form S-3 with the Securities and Exchange Commission (SEC). Upon being declared effective by the SEC, we will initially be limited to selling debt or equity securities under the shelf registration in one or more offerings over a 12 consecutive month period for a total initial public offering price not exceeding one third of our public equity float. That limit, at the time of filing the shelf, was approximately $21.7 million.

     The shelf registration statement is intended to give us the flexibility to sell securities if and when market conditions and circumstances warrant, to provide funding for growth or other strategic initiatives, for debt reduction or refinancing and for other general corporate purposes. The actual amount and type of securities or combination of securities and the terms of those securities, will be determined at the time of sale, if such sale occurs. If and when a particular series of securities is offered, the prospectus supplement relating to that offering will set forth our intended use of the net proceeds.

Appalachia Basin Sale

     On December 24, 2010, we entered into an agreement with Magnum Hunter Resources Corporation (“MHR”) to sell to MHR certain oil and gas properties and related assets in West Virginia. The sale closed in two phases for a total of $39.7 million. The first phase closed on December 30, 2010, for $28 million. The second closed on January 14, 2011, for $11.7 million. The amount received at both closings was paid half in cash and half in MHR common stock. The agreement contained provisions for a third closing if certain conditions are met before May 15, 2011. That deadline has been extended to June 15, 2011. There can be no assurance that the third closing will occur.

     Included in the $39.7 million aggregate purchase price for both closings was approximately $36.7 million representing the purchase price of assets owned by our subsidiary, Quest Eastern Resource (“QER”) pledged as collateral under the QER Loan. Approximately $12.1 million of the net cash consideration and the share consideration received by QER pursuant to the purchase agreement (totaling 3.0 million shares) were paid to the lender, Royal Bank of Canada (“RBC”), in repayment of the QER Loan and as consideration for the release of RBC’s liens encumbering the assets sold, which resulted in payments to RBC of $21.2 million in December 2010 and $9.3 million in January 2011 from the first and second phases of the asset sale. The $9.3 million payment in January 2011 consists of $5.7 million in MHR stock and $3.6 million in cash.

      In connection with the QER Loan, we entered into an asset sale agreement with RBC that allowed us to sell QER or its assets and, in the event the proceeds were not adequate to repay the QER Loan in full, we agreed to pay a portion of such shortfall in cash, stock or a combination thereof. Under the terms of the existing arrangement, prior to the end of the second quarter of 2011, we are required to make a payment to RBC of up to $5.1 million. The amount paid to RBC would be reduced if the third phase of the sale of properties to MHR discussed in Note 2 of Part I, Item 1 of this quarterly report is consummated. We currently expect to make such payment in common stock. We also expect to recover our payment to RBC through release of the escrowed proceeds from the Appalachia Basin asset sale in approximately one year. The asset sale agreement also gives us the option to purchase certain of QER’s remaining assets that secure the QER Loan, including a gathering system and undeveloped acreage.

Credit Facilities

     The following is summary of our outstanding balances and availability under our debt facilities at April 30, 2011 (in thousands).

		Balance				Availability
Borrowing Base Facility		$	182,000			$	41,300
Secured Pipeline Loan			11,000				—
QER Loan			10,423				—
Total		$	203,423			$	41,300

Dilution

     At March 31, 2011, we had 8,290,482 shares of common stock issued and outstanding. In addition, White Deer holds warrants to purchase 19,875,191 shares of common stock at a weighted average exercise price of $3.21, and we have 392,000 unvested restricted stock units outstanding. Consequently, if these shares were included as outstanding, our outstanding shares would be 28,557,673 of which White Deer’s warrants represent approximately 70%. Because we recorded a loss for the quarter, the warrants and restricted stock units would be antidilutive so they are excluded from our diluted share calculations. By exercising their warrants, White Deer can benefit from their respective percentage of all of our profits and growth. In addition, if White Deer begins to sell significant amounts of our

common stock, or if public markets perceive that they may sell significant amounts of our common stock, the market price of our common stock may be significantly impacted.

Contractual Obligations

     We have numerous contractual commitments in the ordinary course of business, debt service requirements and operating lease commitments. During the first quarter of 2011 we entered into new operating leases for compressors utilized in our gathering system. The new leases were entered into on existing compressors that we had previously been leasing on a month-to-month basis. The new compressor leases resulted in an increase to our contractual commitments of approximately $900,000 in 2011 from the amount of our outstanding commitments as of December 31, 2010. Except for these leases and the debt repayments during the first quarter of 2011 described above, as of March 31, 2011, there were no other material changes to our commitments since December 31, 2010.

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;
	•		volatility of oil and natural gas prices;
	•		increases in the cost of drilling, completion and gas gathering or other costs of developing and producing our reserves;
	•		our 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 under Item 1A. Risk Factors included in our annual report on Form 10-K for the year ended December 31, 2010, which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements. Our annual report on Form 10-K for the year ended December 31, 2010, is available on our website at www.pstr.com.

     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.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

     The following table summarizes the estimated volumes, fixed prices and fair value attributable to oil and gas derivative contracts at March 31, 2011. We currently do not have outstanding derivative contracts beyond 2013.

		Remainder of				Year Ending December 31,
		2011				2012				2013				Total
		($ in thousands, except volumes and per unit data)
Natural Gas Swaps
Contract volumes (Mmbtu)			10,202,283				11,000,004				9,000,003				30,202,290
Weighted-average fixed price per Mmbtu		$	6.70			$	7.13			$	7.28			$	7.03
Fair value, net		$	22,613			$	23,122			$	16,327			$	62,062
Natural Gas Basis Swaps
Contract volumes (Mmbtu)			6,441,780				9,000,000				9,000,003				24,441,783
Weighted-average fixed price per Mmbtu		$	(0.69	)		$	(0.70	)		$	(0.71	)		$	(0.70	)
Fair value, net		$	(2,850	)		$	(3,554	)		$	(3,411	)		$	(9,815	)
Crude Oil Swaps
Contract volumes (Bbl)			36,000				42,000				—				78,000
Weighted-average fixed price per Bbl		$	85.90			$	87.90			$	—			$	86.98
Fair value, net		$	(792	)		$	(764	)		$	—			$	(1,556	)
Total fair value, net		$	18,971			$	18,804			$	12,916			$	50,691

ITEM 4. CONTROLS AND PROCEDURES

     Disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) are designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms and that such information is accumulated and communicated to management, including the principal executive officer and the principal financial officer, to allow timely decisions regarding required disclosures. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives.

     In connection with the preparation of this quarterly report on Form 10-Q, our management, under the supervision and with the participation of our principal executive officer and principal financial officer, conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures as of March 31, 2011. Based on that evaluation, our principal executive officer and principal financial officer concluded that, as of March 31, 2011, our disclosure controls and procedures were effective with respect to the recording, processing, summarizing and reporting, within the time periods specified in the SEC’s rules and forms, of information required to be disclosed by us in the reports that we file or submit under the Exchange Act.

     There were no changes in internal control over financial reporting that occurred during the quarter covered by this report that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS.

     See Note 9 in Part I, Item 1 of this Quarterly Report entitled “Commitments and Contingencies,” which is incorporated herein by reference.

ITEM 1A. RISK FACTORS.

     For additional information about our risk factors, see Item 1A. “Risk Factors” in our 2010 10-K.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.

     The information set forth in Note 7 in Part I, Item 1 of this Quarterly Report is incorporated herein by reference in response to this item. The additional warrants and shares of Series B preferred stock issued to White Deer were issued in reliance upon an exemption from registration pursuant to Section 4(2) under the Securities Act of 1933, as amended, which exempts transactions by an issuer not involving any public offering.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES.

     None.

ITEM 5. OTHER INFORMATION.

     None.

ITEM 6. EXHIBITS

10.1†		PostRock 2010 Long-Term Incentive Plan Form of Restricted Share Award Agreement (one-year vesting and change-in- control provisions).
10.2†		PostRock 2011 Management Incentive Program.
31.1		Certification by principal executive officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2		Certification by principal financial officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1		Certification by principal executive officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2		Certification by principal financial officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

PLEASE NOTE: Pursuant to the rules and regulations of the Securities and Exchange Commission, we have filed or incorporated by reference the agreements referenced above as exhibits to this Quarterly Report on Form 10-Q. The agreements have been filed to provide investors with information regarding their respective terms. The agreements are not intended to provide any other factual information about the Company or its business or operations. In particular, the assertions embodied in any representations, warranties and covenants contained in the agreements may be subject to qualifications with respect to knowledge and materiality different from those applicable to investors and may be qualified by information in confidential disclosure schedules no included with the exhibits. These disclosure schedules may contain information that modifies, qualifies and creates exceptions to the representations, warranties and covenants set forth in the agreements. Moreover, certain representations, warranties and covenants in the agreements may have been used for the purpose of allocating risk between the parties, rather than establishing matters as facts. In addition, information concerning the subject matter of the representations, warranties and covenants may have changed after the date of the respective agreement, which subsequent information may or may not be fully reflected in the Company’s public disclosures. Accordingly, investors should not rely on the representations, warranties and covenants in the agreements as characterizations of the actual state of facts about the Company or its business or operations on the date hereof.

SIGNATURES

     Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized this 11th day of May 2011.