PostRock Energy (PSTR) 10-Q 2012 Q2 Quarterly report

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, 2012

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  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§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  x    No  ¨

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

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

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

At August 2, 2012, there were 15,484,625 outstanding shares of the registrant’s common stock having an aggregate market value of $31.3 million based on a closing price of $2.02 per share.

POSTROCK ENERGY CORPORATION

FORM 10-Q

FOR THE QUARTER ENDED JUNE 30, 2012

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	10
Item 4. Controls and Procedures	10
PART II — OTHER INFORMATION
Item 1. Legal Proceedings	11
Item 1A. Risk Factors	11
Item 6. Exhibits	12
SIGNATURES	14

i

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, 2011			June 30, 2012
				(Unaudited)
ASSETS
Current assets
Cash and equivalents	$	349		$	105
Accounts receivable—trade, net		9,123			6,151
Other receivables		1,267			200
Inventory		1,788			1,568
Other		7,492			3,884
Derivative financial instruments		42,803			34,234
Total		62,822			46,142
Oil and natural gas properties, full cost method of accounting, net		124,068			118,897
Pipeline assets, net		59,088			58,069
Other property and equipment, net		14,726			15,673
Other, net		3,497			1,051
Equity investment		12,994			10,471
Derivative financial instruments		29,516			17,360
Total assets	$	306,711		$	267,663
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	6,286		$	3,978
Revenue payable		4,972			3,529
Accrued expenses and other		8,700			5,571
Litigation reserve		3,081			4,415
Current portion of long-term debt		3,000			167,355
Derivative financial instruments		5,223			5,424
Total		31,262			190,272
Derivative financial instruments		4,611			2,999
Long term debt		190,000			—
Asset retirement obligations		11,733			12,130
Other		4,559			348
Total liabilities		242,165			205,749
Commitments and contingencies
Series A Cumulative Redeemable Preferred Stock, $0.01 par value; issued and outstanding—6,000 shares		56,736			60,463
Stockholders’ equity
Preferred stock, $0.01 par value; 5,000,000 authorized shares; 215,662 and 236,231 Series B Voting Preferred Stock issued and outstanding, respectively		2			2
Common stock, $0.01 par value; 40,000,000 authorized shares; 9,935,337 and 12,409,042 issued and outstanding, respectively		99			124
Additional paid-in capital		378,093			382,870
Accumulated deficit		(370,384	)		(381,545	)
Total equity		7,810			1,451
Total liabilities and equity	$	306,711		$	267,663

The accompanying notes are an integral part of these statements.

F-1

POSTROCK ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share data)

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2012			2011			2012
Revenues
Oil and gas sales	$	21,525		$	10,650		$	41,762		$	24,272
Gathering		1,533			474			2,889			1,173
Pipeline		2,466			2,814			5,639			6,242
Total		25,524			13,938			50,290			31,687
Costs and expenses
Production expense		11,406			10,699			23,840			22,200
Pipeline expense		1,356			765			3,016			1,647
General and administrative		5,148			3,878			10,036			8,457
Litigation reserve		100			—			9,600			—
Depreciation, depletion and amortization		6,836			7,781			13,727			14,794
(Gain) loss on disposal of assets		(2,435	)		266			(12,357	)		157
Total		22,411			23,389			47,862			47,255
Operating income (loss)		3,113			(9,451	)		2,428			(15,568	)
Other income (expense)
Realized gain from derivative financial instruments		6,671			18,618			15,907			30,703
Unrealized loss from derivative financial instruments		(1,103	)		(18,777	)		(11,160	)		(18,837	)
Loss from equity investment		—			(6,636	)		—			(2,467	)
Gain on forgiveness of debt		1,647			255			1,647			255
Other income (expense), net		(164	)		7			170			18
Interest expense, net		(2,633	)		(2,524	)		(5,322	)		(5,265	)
Total other income (expense)		4,418			(9,057	)		1,242			4,407
Income (loss) before income taxes		7,531			(18,508	)		3,670			(11,161	)
Income taxes		—			—			—			—
Net income (loss)		7,531			(18,508	)		3,670			(11,161	)
Preferred stock dividends		(1,915	)		(2,155	)		(3,774	)		(4,248	)
Accretion of redeemable preferred stock		(380	)		(501	)		(735	)		(972	)
Net income (loss) available to common stock	$	5,236		$	(21,164	)	$	(839	)	$	(16,381	)
Net income (loss) per common share
Basic	$	0.63		$	(1.71	)	$	(0.10	)	$	(1.39	)
Diluted	$	0.28		$	(1.71	)	$	(0.10	)	$	(1.39	)
Weighted average common shares outstanding
Basic		8,311			12,403			8,283			11,805
Diluted		18,792			12,403			8,283			11,805

The accompanying notes are an integral part of these statements.

F-2

POSTROCK ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)

	Six Months Ended June 30,
	2011			2012
Cash flows from operating activities
Net income (loss)	$	3,670		$	(11,161	)
Adjustments to reconcile net income (loss) to net cash provided by operations
Depreciation, depletion and amortization		13,727			14,794
Stock-based compensation		1,341			1,091
Amortization of deferred loan costs		848			797
Change in fair value of derivative financial instruments		11,160			19,314
Litigation reserve		9,600			—
Loss (gain) on disposal of assets		(12,357	)		157
Gain on forgiveness of debt		(1,647	)		(255	)
Loss from equity investment		—			2,467
Other non-cash changes to net income		(100	)		259
Change in assets and liabilities
Receivables		(426	)		4,039
Payables		(2,859	)		(6,591	)
Other		(1,486	)		1,757
Net cash flows from operating activities		21,471			26,668
Cash flows from investing activities
Restricted cash		28			—
Proceeds from sale of assets		10,682			293
Equipment, development, leasehold and pipeline		(15,287	)		(8,998	)
Net cash flows from investing activities		(4,577	)		(8,705	)
Cash flows from financing activities
Proceeds from issuance of common stock		—			7,514
Equity issuance costs		—			(76	)
Repayments of debt		(16,319	)		(25,645	)
Net cash flows from financing activities		(16,319	)		(18,207	)
Net increase (decrease) in cash		575			(244	)
Cash and equivalents—beginning of period		730			349
Cash and equivalents—end of period	$	1,305		$	105

The accompanying notes are an integral part of these statements.

F-3

POSTROCK ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

(Amounts subsequent to December 31, 2011 are unaudited)

(in thousands, except share data)

	Preferred Shares		Preferred Stock		Common Shares Issued		Common Stock		Additional Paid-in Capital			Accumulated Deficit			Total Equity
Balance, December 31, 2011		215,662	$	2		9,935,337	$	99	$	378,093		$	(370,384	)	$	7,810
Stock-based compensation		—		—		—		—		1,091			—			1,091
Restricted stock grants, net of forfeitures		—		—		287,130		3		(3	)		—			—
Issuance of Series B preferred stock		20,569		—		—		—		—			—			—
Issuance of warrants		—		—		—		—		1,493			—			1,493
Issuance of common stock		—		—		2,186,575		22		7,416			—			7,438
Preferred stock dividends		—		—		—		—		(4,248	)		—			(4,248	)
Preferred stock accretion		—		—		—		—		(972	)		—			(972	)
Net loss		—		—		—		—		—			(11,161	)		(11,161	)
Balance, June 30, 2012		236,231	$	2		12,409,042	$	124	$	382,870		$	(381,545	)	$	1, 451

The accompanying notes are an integral part of these statements.

F-4

POSTROCK ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 1 — Basis of Presentation

PostRock Energy Corporation 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 oil and gas producing properties in the Appalachian 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 (the “KPC Pipeline”). Unless the context requires otherwise, references to “PostRock,” the “Company,” “we,” “us” and “our” refer to PostRock Energy Corporation and its consolidated subsidiaries.

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, 2011 (the “2011
10-K”).

The preparation of condensed consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the condensed 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.

Recently Adopted Accounting Pronouncements

In January 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2010-06,Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements. The update requires reporting entities to provide information about movements of assets among Levels 1 and 2 of the three-tier fair value hierarchy established under FASB ASC 820. The update also requires separate presentation (on a gross basis rather than as one net number) about purchases, sales, issuances, and settlements within the reconciliation of activity in Level 3 fair value measurements. The guidance is effective for any fiscal period beginning after December 15, 2009, except for the requirement to separately disclose purchases, sales, issuances, and settlements, which 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 amendment did not have a material impact on the Company’s consolidated financial statements.

In May 2011, the FASB issued ASU 2011-04Fair 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 amendment did not have a material impact on the Company’s consolidated financial statements.

F-5

POSTROCK ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

In June 2011, the FASB issued 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. Certain provisions in this update relating to the new presentation for reclassifications of items out of accumulated other comprehensive income have been delayed indefinitely. The remaining amendments are to be applied retrospectively and are effective for fiscal years and interim periods within those years beginning after December 15, 2011. The amendment did not have a material impact on the Company’s consolidated financial statements.

Note 2 — Divestitures

Appalachian Basin Sale—In December 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 in December 2010, January 2011 and June 2011 for a total of $44.6 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. 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.

Of the total proceeds received from all three phases of the sale, $6.4 million was set aside in escrow to cover potential claims for indemnity and title defects. In June 2012, $5.7 million of escrowed funds relating to the first and second closing was released after net claims of $219,000 were paid. Of the $5.7 million released to the Company, $1.3 million was retained by the Company while $4.4 million was paid to Royal Bank of Canada (“RBC”) under the previously disclosed asset sale agreement with RBC. The $219,000 of net claims paid out of escrow effectively reduced the net proceeds received on the sale, and along with certain post-closing adjustments, resulted in a $56,000 reduction in the gain on sale recognized in June 2012. At June 30, 2012, the remaining balance in escrow was $564,000. The balance is related to the third closing and scheduled to be released in December 2012. The escrow balance is reflected in the condensed consolidated balance sheet as a component of other current assets. If the entire remaining amount in escrow is released, the Company would retain $164,000 while $400,000 will be paid to a third-party. The amount payable to the third party is reflected in the condensed consolidated balance sheet in “accrued expenses and other.”

F-6

POSTROCK ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Note 3—Other Balance Sheet Items

The following describes the components of the following condensed consolidated balance sheet items (in thousands):

	December 31, 2011		June 30, 2012
Other current assets
Prepaid fees and deposits	$	1,022	$	1,678
Escrowed funds (1)		6,439		564
Other		31		1,642
Total	$	7,492	$	3,884
Other noncurrent assets, net
Intangible assets	$	676	$	530
Deferred financing costs		2,270		—
Noncurrent deposits and other		551		521
Total	$	3,497	$	1,051
Accrued expenses and other
Interest	$	53	$	46
Employee-related costs and benefits		1,294		1,153
Non-income related taxes		41		1,945
Escrowed funds due to third parties (2)		4,981		400
Fees for services		1,042		793
Other		1,289		1,234
Total	$	8,700	$	5,571
Other noncurrent liabilities
Litigation reserve (3)	$	4,111	$	—
Lease termination costs		440		348
Other		8		—
Total	$	4,559	$	348

(1) Escrowed funds relate to the proceeds from the Appalachian Basin sale. The escrowed funds are restricted to cover indemnities and title defects related to the sale. In June 2012, $5.7 million in escrowed funds were released after $219,000 in net claims were paid. The remaining $564,000 is scheduled to be released in December 2012.

(2) The balance at December 31, 2011, represents the portion of escrowed funds from the Appalachian Basin sale that, upon release, would be payable to the RBC and a third party. In June 2012, $4.4 million was paid to RBC and net claims of $219,000 were paid. The balance at June 30, 2012, will be payable to a third party.

(3) Recorded at present value. At June 30, 2012, litigation reserve is presented as a separate item within current liabilities.

Note 4 — Derivative Financial Instruments

The Company is exposed to commodity price risk and management believes it prudent to periodically reduce exposure to cash-flow variability resulting from this volatility. Accordingly, the Company enters into certain derivative financial instruments in order to manage exposure to commodity price risk inherent in its oil and gas production. 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.

F-7

POSTROCK ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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):

Derivative Financial Instruments	Balance Sheet location	December 31, 2011			June 30, 2012
Commodity contracts	Current derivative financial instrument asset	$	42,803		$	34,234
Commodity contracts	Long-term derivative financial instrument asset		29,516			17,360
Commodity contracts	Current derivative financial instrument liability		(5,223	)		(5,424	)
Commodity contracts	Long-term derivative financial instrument liability		(4,611	)		(2,999	)
		$	62,485		$	43,171

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2012			2011			2012
Realized gains (losses)	$	6,671		$	18,618		$	15,907		$	30,703
Unrealized gains (losses)		(1,103	)		(18,777	)		(11,160	)		(18,837	)
Total	$	5,568		$	(159	)	$	4,747		$	11,866

F-8

POSTROCK ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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, 2012.

	Remainder  of 2012			Year Ending December 31,								Total
				2013			2014		2015-2016
	($ in thousands, except per unit data)
Natural Gas Swaps
Contract volumes (Mmbtu)		5,524,592			9,000,003			—		1,047,000			15,571,595
Weighted-average fixed price per Mmbtu	$	5.71		$	7.28		$	—	$	4.00		$	6.51
Fair value, net	$	15,359		$	32,981		$	—	$	(458	)	$	47,882
Natural Gas Basis Swaps
Contract volumes (Mmbtu)		4,524,590			9,000,003			—		—			13,524,593
Weighted-average fixed price per Mmbtu	$	(0.72	)	$	(0.71	)	$	—	$	—		$	(0.71	)
Fair value, net	$	(2,356	)	$	(4,620	)	$	—	$	—		$	(6,976	)
Crude Oil Swaps
Contract volumes (Bbl)		33,342			65,892			61,680		112,056			272,970
Weighted-average fixed price per Bbl	$	93.86		$	101.70		$	97.00	$	92.29		$	95.82
Fair value, net	$	256		$	865		$	557	$	587		$	2,265
Total fair value, net	$	13,259		$	29,226		$	557	$	129		$	43,171

In April 2012, the Company repriced the portion of its natural gas swap contracts expected to settle in June, July and August of 2012 to market prices and received proceeds of $10.8 million. In May 2012, the Company settled the repriced June 2012 contract by entering into new contracts to be settled in 2016. The settlement transaction resulted in a realized loss on derivative instruments of $476,000.

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, 2011:

	Year Ending December 31,
	2012			2013			Total
	($ in thousands, except per unit data)
Natural Gas Swaps
Contract volumes (Mmbtu)		11,000,004			9,000,003			20,000,007
Weighted-average fixed price per Mmbtu	$	7.13		$	7.28		$	7.20
Fair value, net	$	42,803		$	29,516		$	72,319
Natural Gas Basis Swaps
Contract volumes (Mmbtu)		9,000,000			9,000,003			18,000,003
Weighted-average fixed price per Mmbtu	$	(0.70	)	$	(0.71	)	$	(0.71	)
Fair value, net	$	(4,767	)	$	(4,611	)	$	(9,378	)
Crude Oil Swaps
Contract volumes (Bbl)		42,000			—			42,000
Weighted-average fixed price per Bbl	$	87.90		$	—		$	87.90
Fair value, net	$	(456	)	$	—		$	(456	)
Total fair value, net	$	37,580		$	24,905		$	62,485

F-9

POSTROCK ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Note 5 — 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 PayableThe carrying amounts approximate fair value due to the short-term nature or maturity of the instruments.

Commodity Derivative InstrumentsThe 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.

Equity InvestmentThe Company owns an equity investment in Constellation Energy Partners LLC (“CEP”). At June 30, 2012, the investment included 483,531 Class A Member Interests and 5,918,894 Class B Member Interests, for a total 26.5% voting interest in CEP. Fair value for the Class B Member Interests, which are publicly traded, is based on market price and classified as a Level 1 measurement under the fair value hierarchy. Fair value for the Class A Member Interests, classified as a Level 2 measurement, is based on the market price of the publicly traded interests and a premium reflecting certain additional rights. At June 30, 2012, the fair values used for the Class A units and the Class B units were $2.32 and $1.58 per unit, respectively.

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

	Level 1		Level 2			Level 3		Total Net Fair Value
At December 31, 2011
Equity investment	$	11,601	$	1,393		$	—	$	12,994
Derivative financial instruments — assets		—		72,319			—		72,319
Derivative financial instruments — liabilities		—		(9,834	)		—		(9,834	)
Total	$	11,601	$	63,878		$	—	$	75,479
At June 30, 2012
Equity investment	$	9,352	$	1,119		$	—	$	10,471
Derivative financial instruments — assets		—		51,594			—		51,594
Derivative financial instruments — liabilities		—		(8,423	)		—		(8,423	)
Total	$	9,352	$	44,290		$	—	$	53,642

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 six months ended June 30, 2012. In June 2011, the Company transferred 23,517 shares of MHR common stock with a fair value of $159,000 from Level 2 to Level 1 due to the limited amount of time remaining until restrictions on the Company’s ability to trade these securities lapsed in July 2011. The lifting of restrictions enabled the Company to value these securities at published market prices. These securities were subsequently sold in July 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 six months ended June 30, 2011 (in thousands). With respect to Level 3 assets or liabilities, there were no transfers, purchases, sales or issuances during this time period. The Company did not own any Level 3 assets and liabilities during the six month period ended June 30, 2012.

F-10

POSTROCK ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

	Six Months Ended June  30, 2011
Balance at beginning of period	$	(9,853	)
Realized and unrealized gains included in earnings		(2,025	)
Transfers out of Level 3 (1)		9,949
Settlements		1,929
Balance at end of period	$	—

(1) Availability of market based information allowed the Company to reclassify all if its swap contracts tied to Southern Star prices from Level 3 to Level 2 during the second quarter of 2011.

Additional Fair Value Disclosures —The Company has 6,000 outstanding shares of Series A Cumulative Redeemable Preferred Stock (see Note 9 — Redeemable Preferred Stock and Warrants). The fair value and the carrying value of these securities were $62.2 million and $56.7 million, respectively, at December 31, 2011, and $76.6 million and $60.5 million, respectively, at June 30, 2012. 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 13.0% and 9.9% at December 31, 2011, and June 30, 2012, respectively, which was based on companies with similar leverage ratios to PostRock. The Company has classified the valuation of these securities under Level 2 of the fair value hierarchy.

The Company’s 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 6—Equity Investment

The Company believes that its 26.5% voting interest in CEP at June 30, 2012, along with the right to appoint two directors to CEP’s Board provide it the ability to exercise significant influence over the operating and financial policies of CEP. Rather than accounting for the investment under the equity method, the Company elected the fair value option to account for its interest in CEP. The fair value option was chosen as the Company determined that the market price of CEP’s publicly traded interests provided a more accurate fair value measure of the Company’s investment in CEP. The Company has not elected the fair value option for any of its other assets and liabilities. As a result of the decrease in the market price of CEP’s traded interests, the Company recorded losses of $6.6 million and $2.5 million for the three months and six months ended June 30, 2012, respectively. The losses were recorded as a component of other income (expense) in the condensed consolidated statement of operations.

The following table presents summarized financial information of CEP (in thousands):

	Three Months Ended June 30, 2012			Six Months Ended June 30, 2012
Revenues	$	11,812		$	35,372
Gross profit (loss) (1)		(3,569	)		3,838
Net income (loss) from continuing operations		(5,010	)		875
Net income (loss)		(5,010	)		875

(1) Equals revenues less operating expenses

F-11

POSTROCK ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Note 7 — Asset Retirement Obligations

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

	Six Months Ended June 30,
	2011		2012
Asset retirement obligations at beginning of period	$	7,150	$	11,733
Liabilities incurred		44		75
Liabilities settled		—		(98	)
Accretion		322		420
Divestitures		—		—
Asset retirement obligations at end of period	$	7,516	$	12,130

Note 8 — Long-Term Debt

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

	December 31, 2011		June 30, 2012
Borrowing Base Facility	$	190,000	$	167,355
Secured Pipeline Loan		3,000		—
Total debt		193,000		167,355
Less current maturities included in current liabilities		3,000		167,355
Total long-term debt	$	190,000	$	—

The terms of the Company’s credit facilities are described within Note 10 of Item 8. Financial Statement and Supplementary Data in the 2011 10-K. During the six months ended June 30, 2012, the Company made $22.6 million in net payments on its Borrowing Base Facility. In addition, the Company made $3.0 million in payments on the Secured Pipeline Loan, which was fully retired in February 2012. At June 30, 2012, the Company classified the outstanding balance on the Borrowing Base Facility as a current liability to reflect the facility’s maturity date on June 30, 2013.

Effective June 1, 2012, PostRock Energy Services Corporation (“PESC”) and PostRock MidContinent Production, LLC (collectively with PESC, the “Borrowers”), subsidiaries of the Company, entered into an amendment of the Second Amended and Restated Credit Agreement, dated September 21, 2010 (as amended, the “Borrowing Base Facility”), among the Borrowers and RBC, as administrative agent and collateral agent (“Agent”), and the lenders party thereto (the “Lenders”). Effective as of June 1, 2012, the borrowing base under the Borrowing Base Facility was $176 million, a decrease of $24 million from the prior borrowing base. In addition, the amendment provided the following, among other things:

• as long as the total outstanding borrowings exceed the target amount which, at the time of the amendment effective date, is $120 million (the “Target Amount”), (1) the Borrowers will be required to pay additional interest at a rate of 1.5% per year on the excess and (2) the $176 million borrowing base will be reduced on a monthly basis by $1 million until the earlier of September 30, 2012 and the date that the borrowing base has been reduced to an amount equal to or less than the Target Amount;

• PESC has pledged its 100% equity interest in PostRock KPC Pipeline, LLC (“KPC”) to the Agent for the benefit of the Lenders; KPC has guaranteed the indebtedness under the Borrowing Base Facility and has granted a mortgage lien on its interstate pipeline and related assets (the “KPC Pipeline”) to secure such indebtedness contemporaneously with the effective date of the amendment, with the lien on the equity of KPC and the KPC Pipeline being released upon any sale of KPC or the KPC Pipeline and the application of the net available cash proceeds from the sale to reduce outstanding borrowings under the Borrowing Base Facility (which will reduce the borrowing base on a dollar-for-dollar basis unless the total outstandings and the borrowing base are equal to or less than the Target Amount); and KPC will not be permitted to incur any debt (other than normal trade debt) or to grant other liens on its assets;

F-12

POSTROCK ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

• the Company’s subsidiary Constellation Energy Partners Management, LLC has pledged 100% of its equity ownership interest in CEP (the “Constellation Equity”) to secure indebtedness under the Borrowing Base Facility, and may dispose of such interest upon a mandatory prepayment of net available cash proceeds from the disposition to reduce outstanding borrowings under the Borrowing Base Facility (which will not reduce the borrowing base or the Target Amount);

• if the Company did not have a signed purchase agreement for the sale of KPC or the KPC Pipeline by July 15, 2012, the Borrowers would be required to obtain additional equity funding from White Deer Energy L.P. and its affiliates (“White Deer”) of $7.5 million, the proceeds of which will be used to repay outstanding borrowings under the Borrowing Base Facility (which will reduce the borrowing base on a dollar-for-dollar basis); pursuant to the second amendment to the Borrowing Base Facility dated as of July 20, 2012, the equity funding was required to be obtained the earlier of two business days after the filing of this quarterly report or August 17, 2012 (see Note 13);

• upon a disposition of the producing Appalachia shale gas properties, the Borrowers will be required to make a prepayment of net available cash proceeds from the disposition to reduce outstanding borrowings under the Borrowing Base Facility, and the borrowing base and the Target Amount will be reduced by the borrowing base value of the Appalachia assets based upon the most recently delivered reserve report (which borrowing base value, on the amendment effective date, is $10 million);

• upon a material disposition (defined in the amendment to mean a disposition that yields gross proceeds of $1 million or more) of other collateral, an amount equal to the borrowing base value of such collateral will be prepaid on the outstanding borrowings, and if the material disposition involves borrowing base oil and gas properties (other than the Appalachia assets), the borrowing base and the Target Amount will be reduced by the borrowing base value of the collateral so disposed; and

• if at the time of the borrowing base redetermination scheduled for October 31, 2012, there is no borrowing base deficiency, the Borrowers will be entitled to a release of the Agent’s liens on the KPC equity, the KPC Pipeline and the Constellation Equity for no consideration and any such release will not reduce the borrowing base.

The Company was in compliance with all of its financial covenants under the Borrowing Base Facility at June 30, 2012.

As discussed within Note 10 of Item 8. Financial Statement and Supplementary Data in the 2011 10-K, the Company settled its QER Loan in 2011 under terms that met accounting criteria to be classified as a troubled debt restructuring. The settlement in 2011 included an equity payment of $843,000 by issuing 141,186 shares of the Company’s common stock to RBC. By evaluating the maximum sum of future cash flows that could be paid to the lender, RBC, the Company previously recorded gains on debt restructuring of $2.9 million and $1.6 million during the year ended December 31, 2010, and during the second quarter of 2011, respectively. Upon the release of $5.7 million in escrowed proceeds from the Appalachian Basin sale in June 2012 (see Note 2), the Company retained $1.3 million and remitted $4.4 million of these funds to RBC, representing the final payment in connection with the QER Loan. The $1.3 million of escrowed funds retained by the Company included recovery of the $843,000 payment to RBC made in 2011. As a result of the Company’s final evaluation of all payments made to RBC in connection with the QER Loan, an additional gain on debt restructuring of $255,000 was recorded in June 2012.

Note 9 — Redeemable Preferred Stock and Warrants

Prior to July 1, 2013, the Company may accrue dividends on its Cumulative Redeemable Series A Preferred Stock (the “Series A Preferred Stock”) rather than paying them in cash. Whenever dividends are accrued on a quarterly dividend payment date, the liquidation preference of the Series A Preferred Stock is increased by the

F-13

POSTROCK ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

amount of the accrued dividends and additional warrants to purchase shares of PostRock common stock and additional shares of Series B Preferred Stock are issued. 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 $1.5 million during the six months ended June 30, 2012.

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

	Carrying Value of Series A Preferred Stock		Number of Outstanding Series A Preferred Shares		Liquidation Value of Series A Preferred Stock		Number of Outstanding Warrants		Weighted Average Exercise Price of Warrants
December 31, 2011	$	56,736		6,000	$	69,759		21,566,245	$	3.23
Accrued dividends		2,755		—		4,248		2,056,854		2.07
Accretion		972		—		—		—		—
June 30, 2012	$	60,463		6,000	$	74,007		23,623,099	$	3.13

Note 10 — Equity and Earnings per Share

Share-Based Payments —The Company recorded share based compensation expense of $1.0 million and $649,000 for the three months ended June 30, 2011 and 2012, respectively. Expense was $1.3 million and $1.1 million for the six months ended June 30, 2011 and 2012, respectively. Total share-based compensation to be recognized on unvested stock awards and options at June 30, 2012, is $3.0 million over a weighted average period of 1.35 years. The following table summarizes option and restricted awards granted during 2012 and their associated valuation assumptions:

	Number of awards granted		Fair value per option or share		Exercise price		Risk free rate			Volatility
Options
First quarter 2012 employee awards (1)		95,000	$	1.69	$	2.93		0.9	%		76.1	%
Second quarter 2012 employee awards (1)		134,230	$	1.88	$	3.09		1.28	%		74.3	%
Restricted Stock Awards
First quarter 2012 employee awards (2)		153,800	$	3.70		n/a		n/a			n/a
Second quarter 2012 employee awards (1)		141,100	$	3.09		n/a		n/a			n/a
Restricted Stock Units
Second quarter 2012 director awards (3)		120,000	$	2.37		n/a		n/a			n/a

(1) Awards vest ratably over a three year period.

(2) Awards vest in one year.

(3) Awards vest in one year and are deliverable to the participant on the earlier of the fifth anniversary of the grant date or the date of participant’s separation from the Company.

F-14

POSTROCK ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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):

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2012			2011			2012
Net income (loss)	$	7,531		$	(18,508	)	$	3,670		$	(11,161	)
Preferred stock accretion		(380	)		(501	)		(735	)		(972	)
Preferred stock dividends		(1,915	)		(2,155	)		(3,774	)		(4,248	)
Net income (loss) attributable to common stockholders	$	5,236		$	(21,164	)	$	(839	)	$	(16,381	)
Denominator
Common shares		8,310,527			12,403,378			8,283,488			11,804,745
Denominator for basic earnings per share		8,310,527			12,403,378			8,283,488			11,804,745
Effect of potentially dilutive securities
Unvested share-based awards		126,039			—			—			—
Warrants		10,159,326			—			—			—
Stock options		195,957			—			—			—
Denominator for diluted earnings per share		18,791,849			12,403,378			8,283,488			11,804,745
Basic earnings (loss) per share	$	0.63		$	(1.71	)	$	(0.10	)	$	(1.39	)
Diluted earnings (loss) per share	$	0.28		$	(1.71	)	$	(0.10	)	$	(1.39	)
Securities excluded from earnings per share calculation:
Unvested share-based awards		—			231,970			308,175			231,970
Antidilutive stock options		201,250			1,264,538			697,750			1,264,538
Warrants		—			22,915,153			20,204,259			22,915,153

Common Stock Issuance —On February 9, 2012, the Company issued 2,180,233 shares of its common stock to White Deer for proceeds of $7.5 million, which were used to retire the Secured Pipeline Loan and for other general corporate purposes.

Note 11 — Commitments and Contingencies

Litigation— The Company is subject, from time to time, to certain legal proceedings and claims in the ordinary course of conducting its business. 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, would have a material adverse effect on its financial position, results of operations or cash flow.

During 2011, the Company was involved in various royalty owner lawsuits in Kansas and Oklahoma as further described in Note 14 of Part II, Item 8 in the 2011 10-K. These lawsuits were settled in 2011. The Company made a settlement payment of $3.0 million related to the Kansas lawsuit in January 2012 with an additional payment of $4.5 million to be made by January 31, 2013. The Company has accrued $4.4 million at June 30, 2012, related to its outstanding litigation which represents the present value of the remaining payment on its Kansas royalty lawsuit settlement.

Contractual Commitments— The Company has numerous contractual commitments in the ordinary course of business including debt service requirements, operating leases and purchase obligations. During the second quarter of 2012, the Company entered into new contractual commitments for office equipment, data storage services and compressors used in its gathering system. As a result, the $532,000 minimum amount of these contracts over a span of five years would be an increase to the amount included in the Company’s outstanding contractual commitments table at December 31, 2011.

F-15

POSTROCK ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Other than the contractual commitments discussed above and debt repayments during the six months ended June 30, 2012, there were no material changes to the Company’s contractual commitments since December 31, 2011.

Note 12 — Operating Segments

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

	Production			Pipeline		Total
Three months ended June 30, 2011
Revenues	$	23,058		$	2,466	$	25,524
Operating profit	$	8,129		$	232	$	8,361
Three months ended June 30, 2012
Revenues	$	11,124		$	2,814	$	13,938
Operating profit (loss)	$	(6,781	)	$	1,208	$	(5,573	)
Six months ended June 30, 2011
Revenues	$	44,651		$	5,639	$	50,290
Operating profit	$	21,259		$	805	$	22,064
Six months ended June 30, 2012
Revenues	$	25,445		$	6,242	$	31,687
Operating profit (loss)	$	(10,019	)	$	2,908	$	(7,111	)
Identifiable assets
December 31, 2011	$	245,093		$	61,618	$	306,711
June 30, 2012	$	207,588		$	60,075	$	267,663

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2012			2011			2012
Segment operating profit (loss) (1)	$	8,361		$	(5,573	)	$	22,064		$	(7,111	)
General and administrative expenses		(5,148	)		(3,878	)		(10,036	)		(8,457	)
Litigation reserve		(100	)		—			(9,600	)		—
Gain from forgiveness of debt		1,647			255			1,647			255
Gain from derivative financial instruments		5,568			(159	)		4,747			11,866
Interest expense, net		(2,633	)		(2,524	)		(5,322	)		(5,265	)
Loss from equity investment		—			(6,636	)		—			(2,467	)
Other income (expense), net		(164	)		7			170			18
Income (loss) before income taxes	$	7,531		$	(18,508	)	$	3,670		$	(11,161	)

(1) Segment operating profit represents total revenues less costs and expenses directly attributable thereto.

Note 13 — Subsequent Events

On August 1, 2012, White Deer purchased 3,076,923 shares of the Company’s common stock at a price of $1.95 per share, $6.0 million initial liquidation preference of the Company’s Series A Cumulative Redeemable Preferred Stock and warrants to purchase 3,076,923 shares of common stock at an exercise price of $1.95 per share. The total purchase price was $12.0 million. The Company used the net proceeds to repay amounts outstanding under

F-16

POSTROCK ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

the Borrowing Base Facility and for working capital purposes. Following that repayment, the borrowing base under the Borrowing Base Facility was reduced by $7.5 million as of August 2, 2012. The terms of the Series A preferred stock and warrants are substantially the same as the Series A preferred stock and warrants issued in September 2010, except that the warrants are not coupled with a fractional share of Series B Voting Preferred Stock (and therefore have no voting right attached) and warrants issued upon the accrual of dividends on the related Series A preferred stock will be issued with an exercise price of $1.95, rather than the market price at the time of issuance. In addition, the date through which the Company may accrue dividends rather than pay them in cash for all outstanding Series A preferred stock was extended from July 1, 2013 to December 31, 2014.

F-17

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 Appalachian 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, 2011.

2012 Drilling Program Update

For 2012, we budgeted approximately $12.1 million to drill and complete 34 new gas wells in the Cherokee Basin and five new oil wells in central Oklahoma, and recomplete eight oil wells in central Oklahoma and 36 oil wells in the Appalachian Basin. In addition, we budgeted $9.6 million for land, infrastructure and equipment. During the first six months of 2012, we recompleted 36 wells, of which 30 were to increase oil production, and drilled three new oil wells. Capital spending during this period included $4.1 million on drilling and recompletions, $1.6 million to complete our vehicle and equipment efficiency projects, $1.2 million to connect two sections of our gathering system to improve production, $296,000 to complete our consolidation and upgrade of facilities in the Cherokee Basin, $100,000 on land, $377,000 on our interstate pipeline and $1.5 million on information technology and other projects. Our capital spending for the remainder of 2012 is subject to available capital as discussed below in “Sources of Liquidity in 2012 and Capital Requirements.”

The significant reduction in natural gas prices at the end of 2011 has continued into 2012. Prices fell below $2.00 per MMbtu in April 2012 and are currently around $3.00 per MMbtu. These depressed prices may not return to levels that encourage dry gas development for some time. As a result, we have curtailed all capital expenditures related to natural gas and have directed our drilling capital to oil development opportunities consisting of recompletions, workovers and new drilling locations on existing leasehold. This change in capital development focus is a significant contributing factor to our 8.2% decline in gas production and 13.2% increase in oil production when comparing the six month periods ending June 30, 2011 and 2012.

Since March 2012, we have performed 30 Cherokee Basin recompletions. The projects are low cost and should not add significant operating costs. It appears the projects have a 50% success rate and, in aggregate including those that prove unsuccessful, a rate of return greater than 75% at current prices. During the quarter, we also drilled three oil wells in southeast Kansas at a combined cost of only $316,000. Production from the three averaged 20 net barrels a day for the first 30 days. We expect to pursue additional such development opportunities in the near future, including ten to twelve workovers a month for the remainder of the year.

1

Results of Operations

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2012			2011			2012
Revenues
Oil and gas sales	$	21,525		$	10,650		$	41,762		$	24,272
Gathering		1,533			474			2,889			1,173
Total production segment		23,058			11,124			44,651			25,445
Pipeline segment		2,466			2,814			5,639			6,242
Total	$	25,524		$	13,938		$	50,290		$	31,687
Operating profit (loss)
Production	$	8,129		$	(6,781	)	$	21,259		$	(10,019	)
Pipelines		232			1,208			805			2,908
Total segment operating profit (loss)		8,361			(5,573	)		22,064			(7,111	)
General and administrative expenses		(5,148	)		(3,878	)		(10,036	)		(8,457	)
Litigation reserve		(100	)		—			(9,600	)		—
Total operating profit (loss)	$	3,113		$	(9,451	)	$	2,428		$	(15,568	)

Three Months Ended June 30, 2011 Compared to the Three Months Ended June 30, 2012

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

	Three Months Ended June 30,					Increase/
	2011		2012			(Decrease)
	($ in thousands except per unit data)
Production Segment
Oil and gas sales	$	21,525	$	10,650		$	(10,875	)	(50.5	)%
Gathering revenue	$	1,533	$	474		$	(1,059	)	(69.1	)%
Production expense	$	11,406	$	10,699		$	(707	)	(6.2	)%
Depreciation, depletion and amortization	$	5,955	$	6,940		$	985		16.5	%
Gain (loss) on disposal of assets	$	2,432	$	(266	)	$	(2,698	)	(110.9	)%
Production Data
Oil production (Mbbls)		20		24			4		20.0	%
Natural gas production (Mmcfe)		4,624		4,111			(513	)	(11.1	)%
Total production (Mmcfe)		4,742		4,256			(486	)	(10.2	)%
Average daily production (Mmcfe/d)		52.1		46.8			(5.3	)	(10.2	)%
Average Sales Price per Unit (Mcfe)
Natural Gas (Mcf)	$	4.23	$	2.06		$	(2.17	)	(51.3	)%
Oil(Bbl)	$	99.96	$	90.13		$	(9.83	)	(9.8	)%
Natural Gas Equivalent (Mcfe)	$	4.54	$	2.50		$	(2.04	)	(44.9	)%
Average Unit Costs per Mcfe
Production expense	$	2.41	$	2.51		$	0.10		4.1	%
Depreciation, depletion and amortization	$	1.26	$	1.63		$	0.37		29.4	%
Pipeline Segment
Pipeline revenue	$	2,466	$	2,814		$	348		14.1	%
Pipeline expense	$	1,356	$	765		$	(591	)	(43.6	)%
Depreciation and amortization expense	$	881	$	841		$	(40	)	(4.5	)%
Gain on disposal of assets	$	3	$	—		$	(3	)	*	%

* Not meaningful

2

Oil and gas sales decreased $10.9 million, or 50.5%, from $21.5 million during the three months ended June 30, 2011, to $10.6 million during the three months ended June 30, 2012. Lower oil and natural gas prices resulted in decreased revenues of $9.1 million and lower gas production volumes decreased revenue by $2.2 million. These decreases were slightly offset by increased oil revenue of $441,000 resulting from the 20.0% increase in volumes. Our average realized natural gas equivalent prices decreased from $4.54 per Mcfe for the three months ended June 30, 2011, to $2.50 per Mcfe for the three months ended June 30, 2012.

Gathering revenue decreased $1.1 million, or 69.1%, from $1.5 million for the three months ended June 30, 2011, to $474,000 for the three months ended June 30, 2012. The decrease is primarily due to the settlement of the royalty lawsuit which lowered the rates that we receive for gathering royalty interest gas coupled with lower production volumes.

Pipeline revenue increased $348,000, or 14.1%, from $2.5 million for the three months ended June 30, 2011, to $2.8 million for the three months ended June 30, 2012. The increase is a result of higher throughput from growing gas volumes associated with oil production in Osage County, Oklahoma.

Production expense consists of lease operating expenses, production taxes and gathering expense. Production expense decreased $707,000, or 6.2%, from $11.4 million for the three months ended June 30, 2011, to $10.7 million for the three months ended June 30, 2012. The decrease was in part due to field optimization projects we began in the latter half of 2011, which resulted in decreased labor, vehicle and equipment costs of $691,000 and decreased gathering costs of $470,000. A reduction in production taxes of $702,000 also contributed to the decrease. These decreases were offset by a reduction in ability to capitalize costs of $713,000, increased workover expenses of $319,000 and increased maintenance expenses of $241,000 driven by weather related issues in April 2012. Production expense was $2.41 per Mcfe for the three months ended June 30, 2011, as compared to $2.51 per Mcfe for the three months ended June 30, 2012.

Pipeline expense decreased $591,000, or 43.6%, from $1.3 million during the three months ended June 30, 2011, to $765,000 during the three months ended June 30, 2012. Costs were lower in the current period as the prior year period included $223,000 of costs related to integrity testing and maintenance that is scheduled but has not yet occurred this year as well as $194,000 of costs related to a capacity lease that expired at the end of October 2011.

Depreciation, depletion and amortization increased $945,000, or 13%, from $6.8 million during the three months ended June 30, 2011, to $7.7 million during the three months ended June 30, 2012. Depletion and amortization on our production properties increased approximately $985,000, or 16.5%, from $5.9 million during the three months ended June 30, 2011, to $6.9 million during the three months ended June 30, 2012. On a per unit basis, we had an increase of $0.37 per Mcfe from $1.26 per Mcfe during the three months ended June 30, 2011, to $1.63 per Mcfe during the three months ended June 30, 2012. Increased depletion and amortization was primarily due to a higher depletion rate offset by lower production volumes in the current quarter. Depreciation and amortization expense on our pipeline segment decreased $40,000, or 4.5%, from $881,000 during the three months ended June 30, 2011, to $841,000 during the three months ended June 30, 2012.

General and administrative expenses decreased $1.2 million, or 24.7%, from $5.1 million during the three months ended June 30, 2011, to $3.9 million during the three months ended June 30, 2012. The decrease was primarily due to reduced compensation costs of $900,000 and reduced legal fees of $185,000 compared to the prior year period.

Litigation reserve expense was $100,000 for the three months ended June 30, 2011, with none recorded for the three months ended June 30, 2012. The 2011 expense was recorded to increase the litigation reserve for our Oklahoma royalty lawsuits from $5.5 million to $5.6 million, the amount of the settlement, which was paid in July 2011. A separate royalty owner lawsuit in Kansas was settled in 2011 for $7.5 million which included $3.0 million paid in January 2012 and $4.5 million to be paid by January 31, 2013. As part of these settlements, all ambiguity in the calculation of prospective as well as prior royalties in our lease agreements was eliminated.

We recorded a gain on disposal of assets of $2.4 million during the three months ended June 30, 2011, compared to a loss of $266,000 during the current year period. The gain in 2011 was primarily due to the third and final phase of the Appalachia Basin sale in June 2011. Gross proceeds from this phase were $4.9 million.

3

Other income (expense) consists primarily of gains (losses) from derivative instruments, gain (loss) from equity investment, gain on forgiveness of debt and net interest expense. We recorded unrealized losses of $1.1 million and $18.8 million on our derivative contracts for the three months ended June 30, 2011 and 2012, respectively. We recorded realized gains of $6.7 million and $18.6 million on our derivative contracts for the three months ended June 30, 2011 and 2012, respectively. We recorded a mark-to market loss on our equity investment in Constellation Energy Partners LLC (“CEP”) of $6.6 million for the three months ended June 30, 2012, with none recorded in the prior year quarter. Gain on forgiveness of debt was $1.6 million and $255,000 for the three months ended June 30, 2011 and 2012, respectively. The gains were a result of the settlement of our QER Loan under a troubled debt restructuring as discussed inLiquidity and Capital Resourcesbelow. Interest expense, net, was $2.6 million during the three months ended June 30, 2011, and $2.5 million during the three months ended June 30, 2012. Reduced interest charges as a result of lower debt balances were partially offset by accretion charges to increase the present value of our litigation reserve.

Six Months Ended June 30, 2011 Compared to the Six Months Ended June 30, 2012

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

	Six Months Ended June 30,					Increase/
	2011		2012			(Decrease)
	($ in thousands except per unit data)
Production Segment
Oil and gas sales	$	41,762	$	24,272		$	(17,490	)	(41.9	)%
Gathering revenue	$	2,889	$	1,173		$	(1,716	)	(59.4	)%
Production expense	$	23,840	$	22,200		$	(1,640	)	(6.9	)%
Depreciation, depletion and amortization	$	11,906	$	13,102		$	1,196		10.0	%
Gain (loss) on disposal of assets	$	12,354	$	(162	)	$	(12,516	)	(101.3	)%
Production Data
Oil production (Mbbls)		38		43			5		13.2	%
Natural gas production (Mmcfe)		9,186		8,429			(757	)	(8.2	)%
Total production (Mmcfe)		9,415		8,685			(730	)	(7.7	)%
Average daily production (Mmcfe/d)		52.0		47.7			(4.3	)	(8.3	)%
Average Sales Price per Unit (Mcfe)
Natural Gas (Mcf)	$	4.15	$	2.40		$	(1.75	)	(42.2	)%
Oil(Bbl)	$	94.37	$	94.10		$	(0.27	)	(0.3	)%
Natural Gas Equivalent (Mcfe)	$	4.44	$	2.79		$	(1.65	)	(37.2	)%
Average Unit Costs per Mcfe
Production expense	$	2.53	$	2.56		$	0.03		1.1	%
Depreciation, depletion and amortization	$	1.26	$	1.51		$	0.25		19.8	%
Pipeline Segment
Pipeline revenue	$	5,639	$	6,242		$	603		10.7	%
Pipeline expense	$	3,016	$	1,647		$	(1,369	)	(45.4	)%
Depreciation and amortization expense	$	1,821	$	1,692		$	(129	)	(7.1	)%
Gain on disposal of assets	$	3	$	5		$	2		66.7	%

Oil and gas sales decreased $17.5 million, or 41.9%, from $41.8 million during the six months ended June 30, 2011, to $24.3 million during the six months ended June 30, 2012. Lower natural gas prices resulted in decreased revenues of $14.8 million and lower gas production volumes decreased revenue by $3.1 million. These decreases were slightly offset by increased oil revenue of $423,000 resulting primarily from the 13.2% increase in production volume. Our average realized natural gas equivalent prices decreased from $4.44 per Mcfe for the six months ended June 30, 2011, to $2.79 per Mcfe for the six months ended June 30, 2012.

Gathering revenue decreased $1.7 million, or 59.4%, from $2.9 million for the six months ended June 30, 2011, to $1.2 million for the six months ended June 30, 2012. The decrease is primarily due to the settlement of the royalty lawsuit which lowered the rates that we receive for gathering royalty interest gas coupled with lower production volumes.

4

Pipeline revenue increased $603,000, or 10.7%, from $5.6 million for the six months ended June 30, 2011, to $6.2 million for the six months ended June 30, 2012. The increase is the result of gas being produced in Osage County, Oklahoma, in connection with oil drilling activity in the area.

Production expense decreased $1.6 million, or 6.9%, from $23.8 million for the six months ended June 30, 2011, to $22.2 million for the six months ended June 30, 2012. The decrease was in part due to field optimization projects we began in the latter half of 2011, which resulted in decreased labor, vehicle and equipment costs of $1.4 million and decreased gathering costs of $705,000. Also contributing to the decrease was a reduction in production taxes of $1.6 million primarily due to lower gas prices and production. These reductions were offset by decreased capitalized expenses of $1.3 million due to reduced drilling activity, a one-time charge of $368,000 related to our March 2012 field reorganization, increased maintenance expenses of $214,000 and a $247,000 increase across various other expense items. Production expense was $2.53 per Mcfe for the six months ended June 30, 2011, as compared to $2.56 per Mcfe for the six months ended June 30, 2012. Excluding the field reorganization charge, production expense was $2.51 per Mcfe for the six months ended June 30, 2012.

Pipeline expense decreased $1.4 million, or 45.4%, from $3.0 million during the six months ended June 30, 2011, to $1.6 million during the six months ended June 30, 2012. Costs were lower in the current period as the prior year period included $254,000 of costs related to integrity testing and maintenance that is scheduled but has not yet occurred this year, $455,000 of costs related to a capacity lease that expired at the end of October 2011 and $335,000 of costs from an external gas leak that occurred during the first quarter of 2011.

Depreciation, depletion and amortization increased $1.1 million, or 7.8%, from $13.7 million during the six months ended June 30, 2011, to $14.8 million during the six months ended June 30, 2012. Depletion and amortization on our production properties increased approximately $1.2 million, or 10%, from $11.9 million during the six months ended June 30, 2011, to $13.1 million during the six months ended June 30, 2012. On a per unit basis, we had an increase of $0.25 per Mcfe from $1.26 per Mcfe during the six months ended June 30, 2011, to $1.51 per Mcfe during the six months ended June 30, 2012. Increased depletion and amortization was primarily due to a higher depletion rate offset by lower production volumes in the current quarter. Depreciation and amortization expense on our pipeline segment decreased $129,000, or 7.1%, from $1.8 million during the six months ended June 30, 2011, to $1.7 million during the six months ended June 30, 2012.

General and administrative expenses decreased $1.6 million, or 15.7%, from $10.0 million during the six months ended June 30, 2011, to $8.4 million during the six months ended June 30, 2012. The cost reduction is primarily due to lower wages, bonuses and benefits during the current year of $714,000 partially offset by higher contract labor of $183,000. Additionally, all material lawsuits were settled in 2011 driving a reduction in our legal costs of $644,000 and a workman’s compensation payout of $310,000 that was recognized in the 2011 period with no payout in 2012.

Litigation reserve expense was $9.6 million for the six months ended June 30, 2011, with none recorded for the six months ended June 30, 2012. The expense in 2011 was recorded to increase our litigation reserve to the estimated potential cost to resolve royalty owner lawsuits pending in Oklahoma and Kansas at the time. As discussed above, these lawsuits were settled in 2011.

We recorded a gain on disposal of assets of $12.4 million during the six months ended June 30, 2011, compared to a loss of $157,000 during the current year period. The gain in 2011 was primarily due to the second and third phases of the Appalachia Basin sale. Gross proceeds from both phases were $16.6 million.

Other income (expense) consists primarily of gains (losses) from derivative instruments, gain (loss) from equity investment, gain on forgiveness of debt and net interest expense. We recorded unrealized losses of $11.2 million and $18.8 million on our derivative contracts for the six months ended June 30, 2011 and 2012, respectively. We recorded realized gains of $15.9 million and $30.7 million on our derivative contracts for the six months ended June 30, 2011 and 2012, respectively. We recorded a mark-to market loss on our equity investment CEP of $2.5 million for the six months ended June 30, 2012 with none recorded in the prior year. Gain on forgiveness of debt was $1.6 million and $255,000 for the six months ended June 30, 2011 and 2012, respectively. The gains were a result of the settlement of our QER Loan under a troubled debt restructuring. Interest expense, net, was $5.3 million during the six months ended June 30, 2011, and $5.2 million during the six months ended June 30, 2012. Reduced interest charges as a result of lower debt balances were partially offset by accretion charges to increase the present value of our litigation reserve.

5

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 received from the sale of 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, production taxes, interest on our indebtedness and general and administrative expenses.

Our primary sources of liquidity for the six months ended June 30, 2012, were cash generated from our hedging activities, the sale of common stock to White Deer Energy L.P. and its affiliates (“White Deer”), cash flows from operations and borrowings under our borrowing base credit facility. We also generated $1.3 million of cash from the release of escrowed proceeds from our Appalachia Basin sale. At June 30, 2012, we had decreased our debt by $25.6 million from December 31, 2011.

Cash Flows from Operating Activities

Cash flows provided by operating activities increased $5.2 million from $21.5 million for the six months ended June 30, 2011, to $26.7 million for the six months ended June 30, 2012. The increase was driven by an increase in cash settlements of our derivative contracts in part due to the repricing of July and August 2012 hedges during the current quarter, lower operating expenses and a reduction in working capital. Increases to cash flow from operating activities were partially offset by a reduction in oil and gas revenues.

Cash Flows from Investing Activities

Cash flows used in investing activities were $4.6 million for the six months ended June 30, 2011, compared to $8.7 million for the six months ended June 30, 2012. Capital expenditures were $15.3 million and $9.0 million for the six months ended June 30, 2011 and 2012, respectively. We received proceeds from the sale of assets of $10.7 million and $293,000 for six months ended June 30, 2011 and 2012, respectively. Proceeds from the sale of assets in 2011 were primarily from the second and third phases of our Appalachia Basin asset sale. Capital expenditures are lower in the current year period compared to the prior year as we have curtailed spending on natural gas projects in response to depressed prices. The following table sets forth our capital expenditures, including costs we have incurred but not paid, by major categories for the six months ended June 30, 2012 (in thousands):

	Six Months Ended June 30, 2012
Capital expenditures
Leasehold acquisition	$	100
Development		5,317
Pipelines		377
Other items		3,414
Total capital expenditures	$	9,208

Cash Flows from Financing Activities

Cash flows used in financing activities were $16.3 million for the six months ended June 30, 2011, as compared to $18.2 million for the six months ended June 30, 2012. Debt repayments were $16.3 million and $25.6 million for the six months ended June 30, 2011 and 2012, respectively. During February 2012, we issued $7.5 million of common stock to White Deer. Proceeds from this issuance were offset by $76,000 of equity issuance costs.

6

Sources of Liquidity in 2012 and Capital Requirements

We rely on our cash flows from operating activities as a source of internally generated liquidity. During the past three years, our cash flows from operating activities have been sufficient to fund our investing activities. Our long-term ability to generate liquidity internally depends in part on our ability to hedge future production at attractive prices as well as our ability to control operating expenses. This has become especially critical in light of current depressed natural gas prices. To a lesser extent, we have in the past relied on the sale of our non-core production assets to generate liquidity. From time to time, we may also issue equity as an external source of liquidity. On February 9, 2012, we issued 2,180,233 shares of our common stock to White Deer for proceeds of $7.5 million which were used for debt repayment and other general corporate purposes.

At August 2, 2012, after application of the proceeds from the White Deer investment described below, we had cash on hand of $270,000, borrowings of $157.9 million and $1.4 million in outstanding letters of credit. With a borrowing base of $166.5 million, we had $7.2 million available under our borrowing base credit facility and $7.5 million of available liquidity on that date. At June 30, 2012, the outstanding balance on this facility was classified as a current liability to reflect a maturity date of June 30, 2013. Over the past several months we have had discussions with multiple lenders and lender representatives and recently began working with a group in an effort to refinance this facility prior to its maturity. Given current gas prices, we do not anticipate having meaningful liquidity for some time without a refinancing.

Effective June 1, 2012, the borrowing base on our secured borrowing base revolving credit facility was redetermined to be $176 million, a decrease of $24 million from the prior borrowing base. The borrowing base was reduced primarily due to the decline in natural gas price assumptions and the roll off of gas hedges. In conjunction with the borrowing base reduction, we entered into an amendment of the credit facility as discussed in Note 8 in Part I, Item 1 of this Quarterly Report. The amendment included, among others, provisions for further reductions in the borrowing base of $1 million a month until the next borrowing base redermination on October 31, 2012, and additional interest of 1.5% on borrowings above $120 million. We were also required to obtain additional equity funding from White Deer of $7.5 million, with the proceeds used to repay outstanding borrowings under the credit facility, resulting in a permanent reduction to the borrowing base.

On August 1, 2012, White Deer purchased 3,076,923 shares of our common stock at a price of $1.95 per share, $6.0 million initial liquidation preference of our Series A Cumulative Redeemable Preferred Stock and warrants to purchase 3,076,923 shares of common stock at an exercise price of $1.95 per share. The total purchase price was $12.0 million. We used the net proceeds to repay amounts outstanding under our credit facility and for working capital purposes.

We have an effective $100 million universal shelf registration statement on Form S-3. We are initially limited to selling debt or equity securities under the shelf registration statement 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. The 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. In addition, we have entered into an at-the-market issuance sales agreement with a sales agent relating to the offering from time to time of shares of our common stock under the shelf registration statement. Sales of shares of our common stock, if any, may be made directly on the NASDAQ Global Market, on any other existing trading market for the common stock or through a market maker, or in privately negotiated transactions, subject to our approval. Our sales agreement is limited to the sale of up to a number of shares of common stock with an initial offering price not to exceed the amount that can be sold under the registration statement. As of the date of the sales agreement, such amount is limited to approximately $20.3 million. We commenced sales of our common stock under the shelf registration statement in June 2012 and to date have sold 6,342 common shares for proceeds of $13,000, net of commissions.

We are continuing our strategic review of the KPC Pipeline. The review includes a potential sale of the asset which, if consummated, would generate cash and improve our liquidity. We have received bids from potential buyers and are in the process of negotiating definitive documentation.

7

During April 2012 we repriced the portion of our natural gas swap contracts expected to settle in June, July and August of 2012 to market prices for proceeds of $10.8 million. The proceeds were utilized to reduce our debt.

Based on our current borrowing base facility including the required $1 million monthly reductions, we currently believe that cash flows from operations and cash on hand, together with availability under our credit facility, will be sufficient to cover our financial obligations and capital spending for the remainder of 2012. However, we may reduce our capital spending budget in the event that our operating results do not meet our current expectations, such as if commodity prices decline further from current levels. Our capital spending will also depend on the initial drilling results from our planned oil recompletes and new oil wells.

Escrowed proceeds from the Appalachia Basin Sale

In December 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 three phases for a total of $44.6 million. Of the total proceeds received from all three phases of the sale, $6.4 million was set aside in escrow to cover potential claims for indemnity and title defects. In June 2012, $5.7 million of escrowed funds relating to the first and second closing were released after net claims of $219,000 were paid. Of the $5.7 million released, $1.3 million was retained by us while $4.4 million was paid to the Royal Bank of Canada (“RBC”) under the previously disclosed asset sale agreement. At June 30, 2012, the remaining balance in escrow was $564,000. The balance is related to the third closing and is scheduled to be released in December 2012. If the entire remaining amount in escrow is released, we would retain $164,000 while $400,000 will be paid to a third-party.

During 2011, we settled a credit facility with RBC (the “QER Loan”) under terms that met accounting criteria to be classified as a troubled debt restructuring. The settlement included $34.7 million in payments utilizing proceeds from the Appalachia Basin asset sale and an equity payment of $843,000. By evaluating the maximum sum of future cash flows that could be paid to RBC, we previously recorded gains on debt restructuring of $2.9 million and $1.6 million in 2010 and 2011, respectively. Upon the final payment of $4.4 million to RBC out of the escrowed proceeds, an additional gain on debt restructuring of $255,000 was recorded in June 2012. The $1.3 million of escrowed funds retained by us included recovery of the $843,000 equity payment to RBC made in 2011.

Dilution

At August 2, 2012, including 5,257,156 shares of our common stock held by White Deer, we had 15,484,625 shares of common stock issued and outstanding. In addition, we have 27,373,844 outstanding warrants to purchase our common stock of which 26,700,022 are owned by White Deer at an average exercise price of $3.00 and 673,822 are owned by Constellation Energy Group Inc. at an average exercise price of $7.07. We also have 261,937 restricted stock units and 1,261,978 options outstanding granted under our long-term incentive plan. Consequently, if these securities were included as outstanding, our outstanding shares would have been 44,382,384 of which the warrants and common stock owned by White Deer represent approximately 72%. 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 including debt service requirements, operating leases and purchase obligations. During the second quarter of 2012, we entered into new contractual commitments for office equipment, data storage services and compressors used in our gathering system. As a result, the $532,000 minimum amount of these contracts over a span of five years would be an increase to the amount included in the outstanding contractual commitments table at December 31, 2011.

Other than the contractual commitments discussed above and debt repayments during the six months ended June 30, 2012, there were no material changes to our contractual commitments since December 31, 2011.

8

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, 2011, 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, 2011, is available on our website atwww.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.

9

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 June 30, 2012.

	Remainder  of 2012			Year Ending December 31,								Total
				2013			2014		2015-2016
	($ in thousands, except per unit data)
Natural Gas Swaps
Contract volumes (Mmbtu)		5,524,592			9,000,003			—		1,047,000			15,571,595
Weighted-average fixed price per Mmbtu	$	5.71		$	7.28		$	—	$	4.00		$	6.51
Fair value, net	$	15,359		$	32,981		$	—	$	(458	)	$	47,882
Natural Gas Basis Swaps
Contract volumes (Mmbtu)		4,524,590			9,000,003			—		—			13,524,593
Weighted-average fixed price per Mmbtu	$	(0.72	)	$	(0.71	)	$	—	$	—		$	(0.71	)
Fair value, net	$	(2,356	)	$	(4,620	)	$	—	$	—		$	(6,976	)
Crude Oil Swaps
Contract volumes (Bbl)		33,342			65,892			61,680		112,056			272,970
Weighted-average fixed price per Bbl	$	93.86		$	101.70		$	97.00	$	92.29		$	95.82
Fair value, net	$	256		$	865		$	557	$	587		$	2,265
Total fair value, net	$	13,259		$	29,226		$	557	$	129		$	43,171

In April 2012, we repriced the portion of our natural gas swap contracts expected to settle in June, July and August of 2012 to market prices and received proceeds of $10.8 million. In May 2012, we settled the repriced June 2012 contract by entering into new contracts in 2016. The settlement transaction resulted in a realized loss on derivative instruments of $476,000.

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 June 30, 2012. Based on that evaluation, our principal executive officer and principal financial officer concluded that, as of June 30, 2012, 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.

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PART II — OTHER INFORMATION

ITEM 1.LEGAL PROCEEDINGS.

See Note 11 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 2011 10-K.

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ITEM 6.EXHIBITS

3.1	Restated Certificate of Incorporation of PostRock (incorporated herein by reference to Exhibit 3.1 to PostRock’s Current Report on Form 8-K filed on March 10, 2010).
3.2	Certificate of Amendment to Restated Certificate of Incorporation of PostRock (incorporated herein by reference to Exhibit 3.2 to PostRock’s Registration Statement on Form S-8, Registration No. 333-181480).
10.1	Second Amendment to PostRock Energy Corporation 2010 Long-Term Incentive Plan (incorporated herein by reference to Exhibit 4.7 to PostRock’s Registration Statement on Form S-8, Registration No. 333-181480).
10.2*	First Amendment to Second Amended and Restated Credit Agreement, dated as of May 31, 2012, among PostRock Energy Services Corporation and PostRock MidContinent Production, LLC, as Borrowers, Royal Bank of Canada, as Administrative Agent and Collateral Agent, and the lenders party thereto.
10.3*	Second Amendment to Second Amended and Restated Credit Agreement, dated as of July 20, 2012, among PostRock Energy Services Corporation and PostRock MidContinent Production, LLC, as Borrowers, Royal Bank of Canada, as Administrative Agent and Collateral Agent, and the lenders party thereto.
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.
101.INS**	XBRL Instance Document.
101.SCH**	XBRL Taxonomy Extension Schema Document.
101.CAL**	XBRL Taxonomy Extension Calculation Linkbase Document.
101.LAB**	XBRL Taxonomy Extension Labels Linkbase Document.
101.PRE**	XBRL Taxonomy Extension Presentation Linkbase Document.
101.DEF**	Taxonomy Extension Definition Linkbase Document.

* Filed herewith.

** Furnished not filed

† Management contracts and compensatory plans and arrangements

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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.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized this 8th day of August 2012.

PostRock Energy Corporation
By:	/s/ Terry W. Carter
	Terry W. Carter
	Chief Executive Officer and President
By:	/s/ David. J. Klvac
	David J. Klvac
	Executive Vice President, Chief Financial Officer and Chief Accounting Officer

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