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

For the quarterly period ended June 30, 2011

Commission file number: 001-34635

POSTROCK ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

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

     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 August 8, 2011, there were 9,431,168 outstanding shares of the registrant’s common stock having an aggregate market value of $38.7 million based on a closing price of $4.10 per share.

 

 

POSTROCK ENERGY CORPORATION
FORM 10-Q
FOR THE QUARTER ENDED JUNE 30, 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 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			11
Item 1A. Risk Factors			11
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			11
Item 3. Defaults Upon Senior Securities			11
Item 5. Other Information			11
Item 6. Exhibits			12
SIGNATURES			14
EX-31.1
EX-31.2
EX-32.1
EX-32.2
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

POSTROCK ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS
(in thousands, except share and per share data)

		December 31, 2010				June 30, 2011
						(Unaudited)
ASSETS
Current assets
Cash and equivalents		$	730			$	1,305
Accounts receivable — trade, net			11,845				11,092
Other receivables			1,153				2,357
Inventory			6,161				5,088
Other current assets			2,799				7,949
Derivative financial instruments			31,588				29,714
Total			54,276				57,505
Oil and gas properties, full cost accounting, net			116,488				119,443
Pipeline assets, net			61,148				60,229
Other property and equipment, net			15,964				15,091
Other noncurrent assets, net			9,303				4,932
Derivative financial instruments			39,633				30,593
Total assets		$	296,812			$	287,793
LIABILITIES AND EQUITY
Current liabilities
Accounts payable		$	7,030			$	6,139
Revenue payable			5,898				5,557
Accrued expenses and other current liabilities			7,190				11,257
Litigation reserve			1,020				10,620
Current portion of long-term debt			10,500				9,000
Derivative financial instruments			3,792				4,669
Total			35,430				47,242
Derivative financial instruments			6,681				6,050
Long-term debt			209,721				183,000
Asset retirement obligations			7,150				7,516
Other noncurrent liabilities			—				400
Total liabilities			258,982				244,208
Commitments and contingencies
Series A Cumulative Redeemable Preferred Stock, $0.01 par value; issued and outstanding — 6,000 shares			50,622				53,634
Stockholders’ equity
Preferred stock, $0.01 par value; authorized shares — 5,000,000; 195,842 and 202,043 Series B Voting Preferred Stock issued and outstanding at December 31, 2010 and June 30, 2011, respectively			2				2
Common stock, $0.01 par value; authorized shares — 40,000,000; 8,238,982 and 8,429,168 issued and outstanding at December 31, 2010 and June 30, 2011, respectively			82				84
Additional paid-in capital			377,538				376,609
Accumulated deficit			(390,414	)			(386,744	)
Total deficit			(12,792	)			(10,049	)
Total liabilities and equity		$	296,812			$	287,793

The accompanying notes are an integral part of these statements.

POSTROCK ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
(Unaudited)

										(Predecessors)
										January 1,
										2010				March 6, 2010				Six Months
		Three Months Ended June 30,								to March 5,				to				Ended June
		2010				2011				2010				June 30, 2010				30, 2011
Revenues
Oil and gas sales		$	20,120			$	21,525			$	18,659			$	28,591			$	41,762
Gathering			1,474				1,533				1,076				1,904				2,889
Pipeline			2,232				2,466				1,749				3,159				5,639
Total			23,826				25,524				21,484				33,654				50,290
Costs and expenses
Production expense			12,005				11,406				8,645				16,123				23,840
Pipeline expense			1,664				1,356				1,110				2,301				3,016
General and administrative			7,910				5,148				5,735				9,494				10,036
Litigation reserve			50				100				—				1,620				9,600
Depreciation, depletion and amortization			4,905				6,836				4,164				6,008				13,727
(Gain) loss on sale of assets			(32	)			(2,435	)			—				140				(12,357	)
Total			26,502				22,411				19,654				35,686				47,862
Operating income (loss)			(2,676	)			3,113				1,830				(2,032	)			2,428
Other income (expense)
Gain (loss) from derivative financial instruments			(605	)			5,568				25,246				17,968				4,747
Gain on forgiveness of debt			—				1,647				—				—				1,647
Other income (expense), net			19				(164	)			(4	)			(90	)			170
Interest expense, net			(6,325	)			(2,633	)			(5,336	)			(8,423	)			(5,322	)
Total other income (expense)			(6,911	)			4,418				19,906				9,455				1,242
Income (loss) before income taxes			(9,587	)			7,531				21,736				7,423				3,670
Income taxes			—				—				—				—				—
Net income (loss)			(9,587	)			7,531				21,736				7,423				3,670
Net income attributable to non-controlling interest			—				—				(9,958	)			—				—
Net income (loss) attributable to controlling interest			(9,587	)			7,531				11,778				7,423				3,670
Preferred dividends			—				(1,915	)			—				—				(3,774	)
Accretion of redeemable preferred stock			—				(380	)			—				—				(735	)
Net income (loss) available to common stock		$	(9,587	)		$	5,236			$	11,778			$	7,423			$	(839	)
Net income (loss) per common share
Basic		$	(1.19	)		$	0.63			$	0.37			$	0.92			$	(0.10	)
Diluted		$	(1.19	)		$	0.28			$	0.36			$	0.91			$	(0.10	)
Weighted average common shares outstanding
Basic			8,049				8,311				32,137				8,047				8,283
Diluted			8,049				18,792				32,614				8,116				8,283

The accompanying notes are an integral part of these statements.

POSTROCK ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
(Unaudited)

		(Predecessors)
		January 1, 2010 to				March 6, 2010 to				Six Months Ended
		March 5, 2010				June 30, 2010				June 30, 2011
Cash flows from operating activities
Net income		$	21,736			$	7,423			$	3,670
Adjustments to reconcile net income to cash provided by operations
Depreciation, depletion and amortization			4,164				6,008				13,727
Stock-based compensation			808				634				1,341
Amortization of deferred loan costs			2,094				1,558				848
Change in fair value of derivative financial instruments			(21,573	)			(7,359	)			11,160
Litigation reserve			—				—				9,600
Loss (gain) on disposal of property and equipment			—				140				(12,357	)
Gain on forgiveness of debt			—				—				(1,647	)
Other non-cash changes to net income			—				111				(100	)
Change in assets and liabilities
Receivables			777				4,098				(426	)
Payables			743				1,410				(2,859	)
Other			468				(2,317	)			(1,486	)
Cash flows from operating activities			9,217				11,706				21,471
Cash flows from investing activities
Restricted cash			(1	)			154				28
Proceeds from sale of oil and gas properties			—				101				10,682
Equipment, development, leasehold and pipeline			(2,282	)			(9,944	)			(15,287	)
Cash flows from investing activities			(2,283	)			(9,689	)			(4,577	)
Cash flows from financing activities
Proceeds from debt			900				2,100				—
Repayments of debt			(41	)			(13,215	)			(16,319	)
Cash flows from financing activities			859				(11,115	)			(16,319	)
Net increase (decrease) in cash			7,793				(9,098	)			575
Cash and equivalents—beginning of period			20,884				28,677				730
Cash and equivalents—end of period		$	28,677			$	19,579			$	1,305

The accompanying notes are an integral part of these statements.

POSTROCK ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(Amounts subsequent to December 31, 2010 are unaudited)
(in thousands)

						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			—				—				—				1				1,340				—				1,341
Restricted stock grants, net of forfeitures			—				—				49,000				—				—				—				—
Issuance of common stock			—				—				141,186				1				743				—				744
Issuance of Series B preferred stock			6,201				—				—				—				—				—				—
Issuance of warrants			—				—				—				—				1,497				—				1,497
Preferred stock dividends			—				—				—				—				(3,774	)			—				(3,774	)
Preferred stock accretion			—				—				—				—				(735	)			—				(735	)
Net income			—				—				—				—				—				3,670				3,670
Balance, June 30, 2011			202,043			$	2				8,429,168			$	84			$	376,609			$	(386,744	)		$	(10,049	)

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 June 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2011-05 Comprehensive Income (Topic 220): Presentation of Comprehensive Income. ASU 2011-05 requires that all nonowner changes in stockholders’ equity be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. In the two-statement approach, the first statement should present total net income and its components followed consecutively by a second statement that should present total other comprehensive income, the components of other comprehensive income, and the total of comprehensive income. The amendments are to be applied retrospectively and are effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. The Company does not expect the amendments to have a material impact on its financial statements.

     In May 2011, the FASB issued ASU 2011-04 Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs. ASU 2011-04 clarifies the principles and definitions used to measure fair value and expands disclosure requirements in order to achieve greater consistency between U.S. GAAP and International Financial Reporting Standards. The amendment does not require additional fair value measurements and is not intended to establish valuation standards or affect valuation practices outside of financial reporting. ASU 2011-04 is to be applied prospectively and is effective during interim and annual periods beginning after December 15, 2011. The Company does not expect the amendments to have a material impact on its financial statements.

     In January 2010, the FASB issued 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, while the provisions requiring gross presentation of activity within Level 3 assets were adopted beginning with the quarter ended March 31, 2011. The adoption did not materially affect the Company’s 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 West Virginia. The sale closed in three phases for a total of $44.6 million. The first phase closed on December 30, 2010, for $28 million, the second phase closed on January 14, 2011, for $11.7 million and the third phase closed on June 16, 2011, for $4.9 million. The amount received for the first and second phases was paid half in cash and half in MHR common stock, while the amount received for the third phase was paid entirely in cash. Of the proceeds received, $4.2 million, $1.7 million and $564,000 related to the first, second and third closings, respectively, were set aside in escrow to cover indemnities and title defects. Escrowed amounts from the first and second closing are to be released in June 2012 and are reflected in the condensed consolidated balance sheet as a component of other current assets. Escrowed amounts from the third closing are to be released in December 2012 and are reflected in the condensed consolidated balance sheet as a component of other noncurrent assets.

     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 three-phased sale described above. Gains of $9.9 million and $2.5 million, net of $225,000 and $2.4 million in selling costs and adjustments, were recorded in January 2011 and June 2011 related to the second and third phases of the sale. The corresponding reduction in the Company’s oil and gas full cost pool was $1.5 million for the second closing, with no reduction for the third closing.

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; 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,				June 30,
Derivative Financial Instruments		Balance Sheet location				2010				2011
Commodity contracts		Current derivative financial instrument asset				$	31,588			$	29,714
Commodity contracts		Long-term derivative financial instrument asset					39,633				30,593
Commodity contracts		Current derivative financial instrument liability					(3,792	)			(4,669	)
Commodity contracts		Long-term derivative financial instrument liability					(6,681	)			(6,050	)
						$	60,748			$	49,588

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

										(Predecessors)
		Three Months				Three Months				January 1,				March 6, 2010				Six Months
		Ended June				Ended June				2010 to March				to June 30,				Ended June
		30, 2010				30, 2011				5, 2010				2010				30, 2011
Realized gains (losses)		$	7,475			$	6,671			$	3,673			$	10,609			$	15,907
Unrealized gains (losses)			(8,080	)			(1,103	)			21,573				7,359				(11,160	)
Total		$	(605	)		$	5,568			$	25,246			$	17,968			$	4,747

     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 June 30, 2011.

		Remainder of				Year Ending December 31,
		2011				2012				2013				Total
		($ in thousands, except per unit data)
Natural Gas Swaps
Contract volumes (Mmbtu)			6,822,618				11,000,004				9,000,003				26,822,625
Weighted-average fixed price per Mmbtu		$	6.77			$	7.13			$	7.28			$	7.09
Fair value, net		$	16,060			$	25,532			$	18,715			$	60,307
Natural Gas Basis Swaps
Contract volumes (Mmbtu)			4,310,136				9,000,000				9,000,003				22,310,139
Weighted-average fixed price per Mmbtu		$	(0.69	)		$	(0.70	)		$	(0.71	)		$	(0.70	)
Fair value, net		$	(2,187	)		$	(4,047	)		$	(3,715	)		$	(9,949	)
Crude Oil Swaps
Contract volumes (Bbl)			24,000				42,000				—				66,000
Weighted-average fixed price per Bbl		$	85.90			$	87.90			$	—			$	87.17
Fair value, net		$	(264	)		$	(506	)		$	—			$	(770	)
Total fair value, net		$	13,609			$	20,979			$	15,000			$	49,588

     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 June 30, 2011, these investments consisted of 23,517 shares of MHR common stock received as proceeds from the Appalachia Basin sale. The 23,517 shares were sold in July 2011 for approximately $168,000. The Company previously sold 218,095 shares of MHR common stock in June 2011 for $1.5 million and received the proceeds in July 2011.

     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 June 30, 2011
Short term investments — other current assets (1)		$	159			$	—			$	—			$	159
Derivative financial instruments — assets			—				60,307				—				60,307
Derivative financial instruments — liabilities			—				(10,719	)			—				(10,719	)
Total		$	159			$	49,588			$	—			$	49,747

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.

     Other than the activity related to shares of MHR common stock discussed above, there were no movements between Levels 1 and 2 during the periods from January 1 to March 5 and March 6 to June 30, 2010, and for the six months ended June 30, 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 purchases, sales or issuances during the time period presented.

		Predecessors
		January 1, 2010 to				March 6, 2010 to				Six Months Ended
		March 5, 2010				June 30, 2010				June 30, 2011
Balance at beginning of period		$	1,530			$	5,455			$	(9,853	)
Realized and unrealized gains included in earnings			7,254				13,713				(2,025	)
Transfers out of Level 3 (1)			—				—				9,949
Settlements			(3,329	)			(8,206	)			1,929
Balance at end of period		$	5,455			$	10,962			$	—

     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 $62.7 million and $53.6 million, respectively, at June 30, 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 10.3% at December 31, 2010, and June 30, 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				Six Months Ended
		March 5, 2010				June 30, 2010				June 30, 2011
Asset retirement obligations at beginning of period		$	6,552			$	6,648			$	7,150
Liabilities incurred			—				3				44
Liabilities settled			(1	)			(10	)			—
Accretion			97				193				322
Divestitures			—				—				—
Asset retirement obligations at end of period		$	6,648			$	6,834			$	7,516

Note 6 — Long-Term Debt

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

		December 31,				June 30,
		2010				2011
Borrowing Base Facility		$	187,000			$	183,000
Secured Pipeline Loan			13,500				9,000
QER Loan			19,721				—
Total debt			220,221				192,000
Less current maturities included in current liabilities			10,500				9,000
Total long-term debt		$	209,721			$	183,000

     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 three phases that closed in December 2010, January 2011 and June 2011. The $44.6 million aggregate purchase price for the three phases was received in cash and in shares of MHR stock. Included in the $44.6 million total was approximately $41.6 million representing the purchase price of assets owned by one of the Company’s subsidiaries, Quest Eastern Resource LLC (“QER”), pledged as collateral under the QER Loan. From the sale proceeds, QER made payments to the lender, Royal Bank of Canada (“RBC”), in the amount of $21.2 million in December 2010, $9.3 million in January 2011 and $4.3 million in June 2011. The $9.3 million payment in January 2011 consisted of $5.7 million in MHR common stock and $3.6 million in cash while the $4.3 million payment in June 2011 was entirely in cash. Concurrent with the June 2011 payment and pursuant to the terms of an asset sale agreement with RBC, the Company fully settled the outstanding balance of the QER Loan of approximately $843,000 by issuing 141,186 shares of its common stock with a fair value of $744,000 to RBC. The Company expects to recover the full amount of the $843,000 payment to RBC through the release of escrowed proceeds from the Appalachia Basin asset sale in June 2012.

     The settlement of the QER Loan was facilitated by the restructuring of a prior loan (the “PESC Loan”) that met the criteria under accounting guidance to be classified as a troubled debt restructuring. The Company had previously recorded a gain on troubled debt restructuring related to the QER Loan of $2.9 million in 2010. Following a re-evaluation of the maximum sum of future cash flows that would be paid to RBC, the Company recorded an additional gain of $1.6 million during the second quarter of 2011. The gain includes $799,000 of accrued interest

that was forgiven at the time the balance of the loan was settled. The gain is reflected as a “gain on forgiveness of debt” in the condensed consolidated statement of operations.

     Of the $6.4 million in escrowed funds related to the asset sale, $5.9 million is recorded in other current assets and $564,000 is recorded in other noncurrent assets. If all the escrowed funds are released to the Company and after the payment to the Company of approximately $843,000 to cover the issuance of stock to RBC described above, $4.6 million will be paid to RBC and $400,000 will be paid to a third party, with the remaining $614,000 paid to the Company. Because the amount payable to RBC is scheduled to be released from escrow in 12 months, the Company has presented the liability in accrued expenses and other current liabilities on the condensed consolidated balance sheet.

     In addition to the payments described above, the Company made periodic payments of $4.5 million on the Secured Pipeline Loan and net payments of $4.0 million on the Borrowing Base Facility during the six month period ended June 30, 2011. The Company was in compliance with all its financial covenants at June 30, 2011.

Note 7 — Redeemable Preferred Stock and Warrants

     The Company may accrue dividends on its Series A Preferred Stock rather than paying cash prior to July 1, 2013. Whenever dividends are accrued, the liquidation preference on the Series A Preferred Stock is increased by a similar amount, additional warrants to purchase shares of PostRock common stock are issued and additional shares of Series B Preferred Stock are issued as well. The Company records the increase in liquidation preference and the issuance of additional warrants by allocating their relative fair values to the amount of accrued dividends. The allocation results in an increase to the Company’s temporary equity related to the Series A Preferred Stock and an increase to additional paid in capital related to the additional warrants issued. The increase to additional paid in capital related to additional warrants issued was $745,000 and $752,000 in the first and second quarters of 2011, respectively.

     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
		Carrying Value of				Outstanding				Liquidation Value of				Number of				Weighted Average
		Series A Preferred				Series A				Series A Preferred				Outstanding				Exercise Price of
		Stock				Preferred Shares				Stock				Warrants				Warrants
Balance on December 31, 2010		$	50,622				6,000			$	61,980				19,584,205			$	3.16
Accrued dividends			1,114				—				1,859				290,986				6.39
Accretion			355				—				—				—
Balance on March 31, 2011			52,091				6,000				63,839				19,875,191				3.21
Accrued dividends			1,163				—				1,915				329,068				5.82
Accretion			380				—				—				—
Balance on June 30, 2011		$	53,634				6,000			$	65,754				20,204,259			$	3.25

Note 8 — Equity and Earnings per Share

     Share-Based Payments — The Company recorded share based compensation expense of $551,000 and $1.0 million for the three months ended June 30, 2010 and 2011, respectively. Expense for the periods from January 1 to March 5 and March 6 to June 30, 2010, was $808,000 and $634,000, respectively, and $1.3 million for the six months ended June 30, 2011. Total share-based compensation to be recognized on unvested stock awards and options at June 30, 2011, is $1.6 million over a weighted average period of 1.37 years. The following table summarizes option awards granted during 2011 and their associated valuation assumptions:

		Number of				Fair value per
		options granted				option				Exercise price				Risk free rate				Volatility
First quarter 2011 employee awards (1)			18,900			$	3.79			$	6.15				2.00	%			74.7	%
First quarter 2011 director awards (2)			10,000			$	3.02			$	4.80				1.93	%			77.0	%
Second quarter 2011 employee awards (1)			5,500			$	4.51			$	7.30				1.84	%			75.2	%
Second quarter 2011 director awards (2)			160,000			$	4.53			$	7.31				1.91	%			75.2	%

     The following table summarizes restricted share awards granted during 2011:

		Number of
		shares granted				Fair Value Per Share
First quarter 2011 restricted share awards (1)			51,500			$	6.15

     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):

										(Predecessor)
										January 1, 2010				March 6, 2010				Six Months Ended
		Three Months Ended June 30,								to March 5,				to June 30,				June 30,
		2010				2011				2010				2010				2011
Net income (loss) attributable to controlling interests		$	(9,587	)		$	7,531			$	11,778			$	7,423			$	3,670
Preferred stock accretion			—				(380	)			—				—				(735	)
Preferred stock dividends			—				(1,915	)			—				—				(3,774	)
Net income (loss) attributable to common stockholders		$	(9,587	)		$	5,236			$	11,778			$	7,423			$	(839	)
Denominator
Common shares			8,048,998				8,310,527				32,016,327				8,046,771				8,283,488
Weighted average number of unvested share-based awards participating			—				—				121,121				—				—
Denominator for basic earnings per share			8,048,998				8,310,527				32,137,448				8,046,771				8,283,488
Effect of potentially dilutive securities
Unvested share-based awards non-participating			—				126,039				450,751				68,465				—
Warrants							10,159,326
Stock options			—				195,957				26,154				316				—
Denominator for diluted earnings per share			8,048,998				18,791,849				32,614,353				8,115,552				8,283,488
Basic earnings per share		$	(1.19	)		$	0.63			$	0.37			$	0.92			$	(0.10	)
Diluted earnings per share		$	(1.19	)		$	0.28			$	0.36			$	0.91			$	(0.10	)
Securities excluded from earnings per share calculation:
Unvested share-based awards			—				—				—				—				308,175
Antidilutive stock options			19,550				201,250				570,000				19,550				697,750
Warrants			—				—				—				—				20,204,259

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 that, if adversely determined, would have a material adverse effect on its financial position, results of operations or cash flows.

     As further described in Note 14 of Part II, Item 8 in the 2010 10-K, the Company had been sued in royalty owner lawsuits filed in Oklahoma and Kansas.

     In Oklahoma, suits by a group of individual royalty owners and by a putative class representing all remaining royalty owners were filed in the District Court of Nowata County, Oklahoma. The lawsuits alleged that the Company wrongfully deducted post-production costs from the plaintiffs’ royalties and engaged in self-dealing contracts and agreements resulting in a less than market price for the gas production. The Company denied the allegations. Settlements have been reached in each of the cases, and on July 28, 2011, the Court entered an order approving the class action settlement. The Company used cash on hand to fund the $5.6 million in settlements on July 29, 2011.

     The Kansas action is a putative class action filed in the United States District Court for the District of Kansas, brought on behalf of all the Company’s royalty owners in that state. Plaintiffs allege that the Company failed to properly make royalty payments by, among other things, charging post-production costs to royalty owners in violation of the underlying lease contracts, paying royalties based on sale point volumes rather than wellhead volumes, allocating expenses in excess of the actual and reasonable post-production costs incurred, allocating production costs and marketing costs to royalty owners, and making royalty payments after the statutorily prescribed time for doing so without paying interest thereon. 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. Another mediation session is scheduled in mid-August. If the matter cannot be resolved through mediation, the case will proceed with general discovery, a class certification hearing, and, if certified, a trial on the merits.

     At June 30, 2011, the Company had reserved $10.6 million for the estimated cost to resolve these cases. The reserve included $9.5 million and $100,000 added in the first and second quarter of 2011, respectively. After funding the settlement for the Oklahoma lawsuits, the reserve remaining for the estimated cost to resolve the Kansas lawsuit is $5.0 million. There can be no assurance the amount reserved will be sufficient to cover any final settlement or damage awards.

     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 leases convert already utilized compressors from month-to-month to a specified term lease. As a result, the $900,000 minimum amount of these contracts would be an increase to the amount included in the Company’s outstanding commitments table at December 31, 2010.

     Other than the compressor leases and debt repayments during the six months ended June 30, 2011, there were no 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
Three months ended June 30, 2010
Revenues		$	21,594			$	2,232			$	23,826
Operating profit		$	5,583			$	(299	)		$	5,284
Three months ended June 30, 2011
Revenues		$	23,058			$	2,466			$	25,524
Operating profit		$	8,129			$	232			$	8,361
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 June 30, 2010
Revenues		$	30,495			$	3,159			$	33,654
Operating profit		$	9,351			$	(269	)		$	9,082
Six months ended June 30, 2011
Revenues		$	44,651			$	5,639			$	50,290
Operating profit		$	21,259			$	805			$	22,064
Identifiable assets
December 31, 2010		$	232,111			$	64,701			$	296,812
June 30, 2011		$	224,592			$	63,201			$	287,793

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

										(Predecessor)
										January 1,				March 6, 2010				Six Months
		Three Months Ended June 30,								2010 to				to June 30,				Ended June 30,
		2010				2011				March 5, 2010				2010				2011
Segment operating profit (1)		$	5,284			$	8,361			$	7,565			$	9,082			$	22,064
General and administrative expenses			(7,910	)			(5,148	)			(5,735	)			(9,494	)			(10,036	)
Litigation reserve			(50	)			(100	)			—				(1,620	)			(9,600	)
Gain from forgiveness of debt			—				1,647				—				—				1,647
Gain (loss) from derivative financial instruments			(605	)			5,568				25,246				17,968				4,747
Interest expense, net			(6,325	)			(2,633	)			(5,336	)			(8,423	)			(5,322	)
Other income (expense), net			19				(164	)			(4	)			(90	)			170
Income (loss) before income taxes		$	(9,587	)		$	7,531			$	21,736			$	7,423			$	3,670

Note 11 — Subsequent Events

     As discussed in Note 9 — Commitments and Contingencies, on July 28, 2011, the Company finalized the settlements related to its Oklahoma royalty owner lawsuits and the following day the Company used cash on hand to fund the $5.6 million in settlements.

     Effective July 31, 2011, the Company’s borrowing base credit facility was redetermined based on its oil and gas reserves at March 31, 2011. The borrowing base was reduced from $225 million to $200 million.

     On August 8, 2011, the Company purchased a majority of Constellation Energy Group, Inc.’s (“CEG”) interests in Constellation Energy Partners LLC (“CEP”). In the transaction, the Company acquired all 485,065 Class A Member Interests and 3,128,670 Class B Member Interests. In combination, the acquired units represent a 14.9% interest in CEP. CEG’s consideration was comprised of $6.6 million of cash, 1,000,000 shares of PostRock common stock and warrants to acquire an additional 673,822 shares of PostRock. Of the warrants, 224,607 are exercisable for one year at an exercise price of $6.57 a share, 224,607 are exercisable for two years at $7.07 a share and 224,608 for three years at $7.57 a share.

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 during the first half of 2011 include:

•

Closed on the second and third phases of our Appalachia Basin sale for $11.7 million and $4.9 million, respectively.

•

Decreased debt by $28.2 million from December 31, 2010, including the full settlement of our QER Loan.

•

Settled all of our Oklahoma royalty interest owner lawsuits for $5.6 million which was funded in July 2011.

•

Brought 55 new oil and gas wells online in the Cherokee Basin, of which 10 were drilled prior to 2011, recompleted 54 wells and returned 49 wells in the basin to production.

2011 Drilling Program Update

     We have budgeted $43.6 million for our 2011 drilling program. During the first half of 2011, we drilled and connected 45 development wells, completed 10 new wells drilled in prior periods, recompleted or connected 54 wells and returned 49 wells to production in the Cherokee Basin. Though individual well results varied by area, production from the wells brought on-line during the first half of 2011 is meeting cumulative production expectations. We have spent $13.7 million for drilling and completion through June 30, 2011, compared to $22.0 million budgeted. We continue to evaluate our drilling program in an effort to ensure all projects provide an attractive rate of return, but do not expect to spend our full budgeted drilling program amount during 2011.

Constellation Energy Partners, LLC

     On August 8, 2011, we purchased a majority of Constellation Energy Group, Inc.’s (“CEG”) interests in Constellation Energy Partners LLC (“CEP”). In the transaction, we acquired 485,065 Class A Member Interests and 3,128,670 Class B Member Interests. In combination, the acquired units represent a 14.9% interest in CEP. The consideration paid to CEG was comprised of $6.6 million of cash, 1,000,000 shares of PostRock common stock and warrants to acquire an additional 673,822 shares of PostRock. Of the warrants, 224,607 are exercisable for one year at an exercise price of $6.57 a share, 224,607 are exercisable for two years at $7.07 a share and 224,608 for three years at $7.57 a share. The cash was funded with borrowings under our credit facility. Both PostRock and CEP each have the majority of their assets in the Cherokee Basin of Kansas and Oklahoma. The acquisition provides an opportunity for us to pursue increased efficiency in the Cherokee Basin through cooperation with CEP and others.

Results of Operations

     In March 2010, PostRock completed the recombination of its three predecessor entities. The results of operations for the six months ended June 30, 2010, represent the combined results of these predecessor entities and PostRock. The results of operations for all other periods presented 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								Six Months Ended
		June 30,								June 30,
		2010				2011				2010				2011
Revenues
Oil and gas sales		$	20,120			$	21,525			$	47,250			$	41,762
Gathering			1,474				1,533				2,980				2,889
Total production segment			21,594				23,058				50,230				44,651
Pipeline segment			2,232				2,466				4,908				5,639
Total		$	23,826			$	25,524			$	55,138			$	50,290
Operating profit
Production		$	5,583			$	8,129			$	16,867			$	21,259
Pipelines			(299	)			232				(220	)			805
Total segment operating profit			5,284				8,361				16,647				22,064
General and administrative expenses			(7,910	)			(5,148	)			(15,229	)			(10,036	)
Litigation reserve			(50	)			(100	)			(1,620	)			(9,600	)
Total operating profit		$	(2,676	)		$	3,113			$	(202	)		$	2,428

Three Months Ended June 30, 2010 Compared to the Three Months Ended June 30, 2011

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

		Three Months Ended
		June 30,								Increase/
		2010				2011				(Decrease)
		($ in thousands except per unit data)
Production Segment
Oil and gas sales		$	20,120			$	21,525			$	1,405				7.0	%
Gathering revenue		$	1,474			$	1,533			$	59				4.0	%
Production expense		$	12,005			$	11,406			$	(599	)			(5.0	)%
Depreciation, depletion and amortization		$	4,038			$	5,955			$	1,917				47.5	%
Gain (loss) on sale of assets		$	32			$	2,432			$	2,400				*	%
Production Data
Total production (Mmcfe)			4,910				4,742				(168	)			(3.4	)%
Average daily production (Mmcfe/d)			54.0				52.1				(1.90	)			(3.5	)%
Average Sales Price per Unit (Mcfe)
Natural Gas (Mcf)		$	3.92			$	4.23			$	0.31				7.9	%
Oil(Bbl)		$	74.73			$	99.96			$	25.23				33.8	%
Natural Gas Equivalent (Mcfe)		$	4.10			$	4.54			$	0.44				10.7	%
Average Unit Costs per Mcfe
Production expense		$	2.45			$	2.41			$	(0.04	)			(1.6	)%
Depreciation, depletion and amortization		$	0.82			$	1.26			$	0.44				53.7	%
Pipeline Segment
Pipeline revenue		$	2,232			$	2,466			$	234				10.5	%
Pipeline expense		$	1,664			$	1,356			$	(308	)			(18.5	)%
Depreciation and amortization expense		$	867			$	881			$	14				1.6	%
Gain (loss) on sale of assets		$	—			$	3			$	3				*	%