PostRock Energy (PSTR) 10-Q 2013 Q3 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 September 30, 2013

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	(I.R.S. Employer
incorporation or organization)	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 November 1, 2013, there were 29,138,587 outstanding shares of the registrant’s common stock having an aggregate market value of $42.3 million based on a closing price of $1.45 per share.

POSTROCK ENERGY CORPORATION

FORM 10-Q

FOR THE QUARTER ENDED SEPTEMBER 30, 2013

TABLE OF CONTENTS

	PART I — FINANCIAL INFORMATION
Item 1.	Financial Statements	F-1
	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’ Deficit	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	7
Item 4.	Controls and Procedures	7
	PART II — OTHER INFORMATION
Item 1A.	Risk Factors	8
Item 6.	Exhibits	8
SIGNATURES		10

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,		September 30,
	2012		2013
			(Unaudited)
ASSETS
Current assets
Cash and equivalents	$	525	$	321
Restricted cash		1,500		—
Accounts receivable—trade, net		7,207		7,574
Other receivables		180		282
Inventory		990		996
Other		2,100		747
Derivative financial instruments		1,771		2,646
Total		14,273		12,566
Oil and natural gas properties, full cost method of accounting, net		107,531		132,518
Other property and equipment, net		14,244		14,624
Equity investment		7,820		13,005
Derivative financial instruments		615		694
Other, net		2,180		2,014
Total assets	$	146,663	$	175,421
LIABILITIES AND STOCKHOLDERS’ DEFICIT
Current liabilities
Accounts payable	$	9,373	$	8,334
Revenue payable		4,447		4,344
Accrued expenses and other		4,928		4,291
Derivative financial instruments		4,449		1,406
Total		23,197		18,375
Derivative financial instruments		2,638		1,433
Long term debt		57,500		86,500
Asset retirement obligations		10,868		11,565
Other		316		119
Total liabilities		94,519		117,992
Commitments and contingencies
Series A Cumulative Redeemable Preferred Stock, $0.01 par value; issued and outstanding—7,250 shares		73,152		81,242
Stockholders’ equity
Preferred stock, $0.01 par value; 5,000,000 authorized shares; 265,095 and 313,936 shares of Series B Voting Preferred Stock issued and outstanding, respectively		3		3
Common stock, $0.01 par value; 100,000,000 authorized shares; issued—21,309,159 and 24,915,632; outstanding—21,309,159 and 24,636,051, respectively		213		249
Additional paid-in capital		396,732		395,964
Treasury stock, at cost		—		(414)
Accumulated deficit		(417,956)		(419,615)
Total stockholders’ deficit		(21,008)		(23,813)
Total liabilities and stockholders’ deficit	$	146,663	$	175,421

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 September 30,				Nine Months Ended September 30,
	2012		2013		2012		2013
Revenues
Natural gas sales	$	10,819	$	12,426	$	31,069	$	39,302
Crude oil sales		2,232		5,552		6,254		12,953
Gathering		646		636		1,819		2,006
Total		13,697		18,614		39,142		54,261
Costs and expenses
Production expense		9,917		9,983		32,117		30,460
General and administrative		3,495		3,450		11,329		11,255
Depreciation, depletion and amortization		7,321		6,957		20,423		20,078
Impairment of oil and gas properties		4,309		—		4,309		—
(Gain) loss on disposal of assets		64		(159)		226		(169)
Acquisition cost		—		62		—		62
Total		25,106		20,293		68,404		61,686
Operating loss		(11,409)		(1,679)		(29,262)		(7,425)
Other income (expense)
Realized gains (losses) from derivative financial instruments		2,666		(145)		33,369		(2,348)
Unrealized gains (losses) from derivative financial instruments		(6,523)		1,322		(25,360)		5,202
Gain (loss) from equity investment		(2,111)		740		(4,578)		5,185
Gain on forgiveness of debt		—		—		255		—
Other income		62		—		80		20
Interest expense, net		(2,615)		(883)		(7,835)		(2,293)
Total		(8,521)		1,034		(4,069)		5,766
Loss from continuing operations before income taxes		(19,930)		(645)		(33,331)		(1,659)
Income taxes		—		—		—		—
Loss from continuing operations		(19,930)		(645)		(33,331)		(1,659)
Loss from discontinued operations		(5,244)		—		(3,004)		—
Net loss		(25,174)		(645)		(36,335)		(1,659)
Preferred stock dividends		(2,341)		(2,907)		(6,589)		(8,470)
Accretion of redeemable preferred stock		(568)		(877)		(1,540)		(2,481)
Net loss attributable to common stockholders	$	(28,083)	$	(4,429)	$	(44,464)	$	(12,610)
Net loss per share common share
Basic loss per share—continuing operations	$	(1.58)	$	(0.18)	$	(3.26)	$	(0.52)
Basic loss per share—discontinued operations	$	(0.36)	$	—	$	(0.24)	$	—
Basic loss per share	$	(1.94)	$	(0.18)	$	(3.50)	$	(0.52)
Diluted loss per share—continuing operations	$	(1.58)	$	(0.18)	$	(3.26)	$	(0.52)
Diluted loss per share—discontinued operations	$	(0.36)	$	—	$	(0.24)	$	—
Diluted loss per share	$	(1.94)	$	(0.18)	$	(3.50)	$	(0.52)
Weighted average common shares outstanding
Basic		14,477		25,000		12,702		24,061
Diluted		14,477		25,000		12,702		24,061

The accompanying notes are an integral part of these statements.

F-2

POSTROCK ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)

	Nine Months Ended
	September 30,
	2012		2013
Cash flows from operating activities
Net loss	$	(36,335)	$	(1,659)
Adjustments to reconcile net loss to net cash from operations
Depreciation, depletion and amortization		22,960		20,078
Impairment of oil and gas properties		4,309		—
Share-based and other compensation		1,601		2,976
Amortization of deferred loan costs		1,208		334
Change in fair value of derivative financial instruments		25,836		(5,202)
Loss (gain) on disposal of assets		5,811		(169)
Gain on forgiveness of debt		(255)		—
Loss (gain) from equity investment		4,578		(5,185)
Other non-cash changes to items affecting net loss		389		—
Changes in operating assets and liabilities
Receivables		3,253		(469)
Payables		(8,850)		(2,426)
Other		4,927		643
Net cash flows from operating activities		29,432		8,921
Cash flows from investing activities
Restricted cash		—		1,500
Expenditures for equipment, development, leasehold and pipeline		(12,276)		(43,601)
Proceeds from sale of assets		53,201		372
Net cash flows from (used in) investing activities		40,925		(41,729)
Cash flows from financing activities
Proceeds from debt		—		29,000
Repayments of debt		(90,145)		—
Debt and equity financing costs		(81)		(472)
Proceeds from issuance of preferred stock and warrants		6,000		—
Proceeds from issuance of common stock		13,682		4,076
Net cash flows from (used in) financing activities		(70,544)		32,604
Net decrease in cash and cash equivalents		(187)		(204)
Cash and equivalents beginning of period		349		525
Cash and equivalents end of period	$	162	$	321

The accompanying notes are an integral part of these statements.

F-3

POSTROCK ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF STOCKHOLDERS’ DEFICIT

(Amounts subsequent to December 31, 2012 are unaudited)

(in thousands, except share data)

		Preferred		Common	Common		Additional		Shares of					Total
	Preferred	Stock		Shares	Stock		Paid-in		Treasury	Treasury		Accumulated		(Deficit)
	Shares	Par Value		Issued	Par Value		Capital		Stock	Stock		Deficit		Equity
Balance, December 31, 2012	265,095	$	3	21,301,159	$	213	$	396,732	—	$	—	$	(417,956)	$	(21,008)
Stock-based compensation	—		—	—		—		2,114	—		—		—		2,114
Restricted stock grants, net of forfeitures	—		—	397,801		4		(4)	—		—		—		—
Funding of 401K and deferred compensation plans	—		—	497,757		5		1,126	(279,581)		(414)		—		717
Issuance of Series B preferred stock	48,841		—	—		—		—	—		—		—		—
Issuance of warrants	—		—	—		—		2,860	—		—		—		2,860
Issuance of common stock, net	—		—	2,718,915		27		4,087	—		—		—		4,114
Preferred stock dividends	—		—	—		—		(8,470)	—		—		—		(8,470)
Preferred stock accretion	—		—	—		—		(2,481)	—		—		—		(2,481)
Net loss	—		—	—		—		—	—		—		(1,659)		(1,659)
Balance, September 30, 2013	313,936	$	3	24,915,632	$	249	$	395,964	(279,581)	$	(414)	$	(419,615)	$	(23,813)

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. Its primary production activity is focused in the Cherokee Basin, a 15-county region in southeastern Kansas and northeastern Oklahoma. It also has oil producing properties in Oklahoma and minor oil and gas producing properties in the Appalachian Basin. The Company previously owned an interstate natural gas pipeline in its PostRock KPC Pipeline, LLC (“KPC”) subsidiary. KPC was sold in September 2012 and its results are reported as a discontinued operation in the condensed consolidated financial statements. 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, 2012 (the “2012 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.

F-5

POSTROCK ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Note 2 — Other Balance Sheet Items

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

	December 31,		September 30,
	2012		2013
Other current assets
Prepaid fees and deposits	$	1,036	$	747
Escrowed funds from Appalachian Basin sale (1)		564		—
Escrowed funds from KPC sale (2)		500		—
Total	$	2,100	$	747
Other noncurrent assets, net
Deferred financing costs	$	1,668	$	1,526
Noncurrent deposits and other		512		488
Total	$	2,180	$	2,014
Accrued expenses and other
Interest	$	56	$	31
Employee-related costs and benefits		1,790		1,467
Non-income related taxes		88		1,742
Escrowed funds due to third parties (3)		400		—
KPC site cleanup costs (4)		313		—
Fees for services		1,327		192
Other		954		859
Total	$	4,928	$	4,291
Other noncurrent liabilities
Lease termination costs	$	255	$	119
Other		61		—
Total	$	316	$	119

____________

(1)Escrowed funds related to the proceeds from the Appalachian Basin sale. The escrowed funds were restricted to cover indemnities and title defects related to the sale. The remaining balance at December 31, 2012 of $564,000 was released to the purchaser in January 2013.

(2)Escrowed funds related to the proceeds from the KPC sale and were released to the Company in January 2013 upon acceptable cleanup of a site previously owned by KPC.

(3)The balance at December 31, 2012, represented escrowed funds from the Appalachian Basin sale that were released to the purchaser in January 2013.

(4)Represent accrued costs for cleanup of a site previously owned by KPC, as discussed above.

Note 3 — Derivative Financial Instruments

The Company is exposed to commodity price risk and management believes it prudent to periodically reduce exposure to cash-flow variability resulting from this volatility. Accordingly, the Company enters into certain derivative financial instruments in order to manage exposure to commodity price risk inherent in its oil and gas production. Derivative financial instruments are also used to manage commodity price risk inherent in customer pricing requirements and to fix margins on the future sale of natural gas. Specifically, the Company may utilize futures, swaps and options.

Derivative instruments expose the Company to counterparty credit risk. The Company’s commodity derivative instruments are currently with two 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.

F-6

POSTROCK ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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. At September 30, 2013, the Company was a net obligor with respect to outstanding derivative contracts with one of its counterparties and therefore utilized its own credit risk in estimating the fair value of those derivatives.

The Company does not designate its derivative financial instruments as hedging instruments for financial accounting purposes and, as a result, it recognizes the change in the respective instruments’ fair value currently in earnings. The table below outlines the classification of derivative financial instruments on the condensed consolidated balance sheet and their financial impact on the condensed consolidated statements of operations at and for the periods indicated (in thousands):

		December 31,		September 30,
Derivative Financial Instruments	Balance Sheet location	2012		2013
Commodity contracts	Current derivative financial instrument asset	$	1,771	$	2,646
Commodity contracts	Long-term derivative financial instrument asset		615		694
Commodity contracts	Current derivative financial instrument liability		(4,449)		(1,406)
Commodity contracts	Long-term derivative financial instrument liability		(2,638)		(1,433)
		$	(4,701)	$	501

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 September 30,				Nine Months Ended September 30,
	2012		2013		2012		2013
Realized gains (losses)	$	2,666	$	(145)	$	33,369	$	(2,348)
Unrealized gains (losses)		(6,523)		1,322		(25,360)		5,202
Total gain (loss) from derivative financial instruments	$	(3,857)	$	1,177	$	8,009	$	2,854

In December 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2011-11 Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities requiring entities to disclose information about offsetting and related arrangements to enable users of financial statements to understand the effect of those arrangements on the financial position of an entity. The disclosure affects all entities with financial instruments and derivatives that are either offset on the balance sheet or subject to a master netting arrangement, irrespective of whether they are offset on the balance sheet. This information will enable users of an entity’s financial statements to evaluate the effect or potential effect of netting arrangements on an entity’s financial position, including the effect or potential effect of rights of setoff associated with certain financial instruments and derivative instruments. The guidance is effective for annual periods beginning on or after January 1, 2013, and interim periods within those annual periods. Other than the additional disclosure requirements, the Company’s adoption of this guidance did not have an impact on its financial statements.

The Company entered into an International Swap Dealers Association Master Agreement (ISDA) with each of its two counterparties for which it holds derivative contracts. The ISDA is a standard contract that governs all derivative contracts entered into between the Company and the respective counterparty. The ISDA allows for offsetting of amounts payable or receivable between the Company and the counterparty, at the election of both parties, for transactions that occur on the same date and in the same currency. The Company has multiple oil swap contracts that could be offset under these provisions but has elected not to offset the fair values of its derivative assets against the fair value of its derivative liabilities on its condensed consolidated balance sheets. The ISDA also includes a master netting arrangement in the event of early termination or default.

F-7

POSTROCK ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The following table discloses and reconciles the gross amounts as presented in the condensed consolidated balance sheets to the net amounts allowed under a master netting arrangement (in thousands). Amounts not offset on the condensed consolidated balance sheets represent positions that do not meet all the conditions for "a right of offset" or positions for which the Company has elected not to offset.

	December 31,		September 30,
	2012		2013
Derivative Assets
Gross amounts of recognized assets	$	2,386	$	3,340
Gross amounts offset in the balance sheet		—		—
Net amounts of assets presented in the balance sheet		2,386		3,340
Gross amounts not offset in the balance sheet		(2,386)		(1,685)
Net amount	$	—	$	1,655
Derivative Liabilities
Gross amounts of recognized liabilities	$	7,087	$	2,839
Gross amounts offset in the balance sheet		—		—
Net amounts of liabilities presented in the balance sheet		7,087		2,839
Gross amounts not offset in the balance sheet		(2,386)		(1,685)
Net amount	$	4,701	$	1,154

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 September 30, 2013.

	Remainder of		Year Ending December 31,
	2013		2014		2015		2016		Total
	($ in thousands, except per unit data)
Natural Gas Swaps
Contract volumes (Mmbtu)		2,903,679		10,327,572		8,983,560		7,814,028		30,028,839
Weighted-average fixed price per Mmbtu	$	4.01	$	4.01	$	4.01	$	4.01	$	4.01
Fair value, net	$	1,193	$	1,530	$	(402)	$	(1,121)	$	1,200
Natural Gas Basis Swaps
Contract volumes (Mmbtu)		2,268,494		—		—		—		2,268,494
Weighted-average fixed price per Mmbtu	$	(0.75)	$	—	$	—	$	—	$	(0.75)
Fair value, net	$	(1,223)	$	—	$	—	$	—	$	(1,223)
Crude Oil Swaps
Contract volumes (Bbl)		28,854		116,076		71,568		65,568		282,066
Weighted-average fixed price per Bbl	$	99.76	$	95.19	$	92.73	$	90.33	$	93.90
Fair value, net	$	(52)	$	(22)	$	280	$	318	$	524
Total fair value, net	$	(82)	$	1,508	$	(122)	$	(803)	$	501

Note 4 — Fair Value Measurements

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

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

Commodity Derivative Instruments — The Company’s oil and gas derivative instruments may consist of variable to fixed price swaps, collars and basis swaps. When possible, the Company estimates the fair values of these instruments based on published forward

F-8

POSTROCK ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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 Investment — The Company owns an equity investment in Constellation Energy Partners LLC (“CEP”), which consisted of 484,097 Class A Member Interests and 5,918,894 Class B Member Interests at September 30, 2013 (see Note 5 —  Equity Investment).  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 liquidity discount as the units are not publicly traded. At September 30, 2013, the fair values used for the Class A units and the Class B units were $0.70 and $2.14 per unit, respectively.

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

							Total Net Fair
	Level 1		Level 2		Level 3		Value
At December 31, 2012
Equity investment	$	6,984	$	836	$	—	$	7,820
Derivative financial instruments—assets		—		2,386		—		2,386
Derivative financial instruments—liabilities		—		(7,087)		—		(7,087)
Total	$	6,984	$	(3,865)	$	—	$	3,119
At September 30, 2013
Equity investment	$	12,666	$	339	$	—	$	13,005
Derivative financial instruments—assets		—		3,340		—		3,340
Derivative financial instruments—liabilities		—		(2,839)		—		(2,839)
Total	$	12,666	$	840	$	—	$	13,506

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 nine months ended September 30, 2013. The Company has not owned any Level 3 assets or liabilities since 2012.

Additional Fair Value Disclosures — The Company has 7,250 outstanding shares of Series A Cumulative Redeemable Preferred Stock (“Series A Preferred Stock”) (see Note 8 — Redeemable Preferred Stock and Warrants) at September 30, 2013. The fair value and the carrying value of the Series A Preferred Stock were $106.4 million and $73.2 million, respectively, at December 31, 2012, and $121.5 million and $81.2 million, respectively, at September 30, 2013. 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 7.1% and 5.0% at December 31, 2012, and September 30, 2013, 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 5 — Equity Investment

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.

The following table presents the mark-to-market gains (losses) on our equity investment, which are recorded as a component of other

F-9

POSTROCK ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

income (expense) in the condensed consolidated statements of operations (in thousands):

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2012		2013		2012		2013
Mark to market gains (losses) on equity investment	$	(2,111)	$	740	$	(4,578)	$	5,185

The following table presents summarized financial information of CEP for the three and six months ended June 30, 2012 and 2013 (in thousands). The information was obtained from CEP’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2013, which is publicly available. Information for the current quarter is not available at this time but will be available on CEP’s Quarterly Report on Form 10-Q for the quarter ended September  30, 2013, which will be filed on or around November 14, 2013.

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2012		2013		2012		2013
Revenues	$	9,199	$	15,388	$	29,813	$	20,488
Gross profit (loss)(1)		(2,238)		1,872		5,970		(7,490)
Net income (loss)		(5,010)		1,112		875		(12,220)

____________

(1) Equals revenues less operating expenses

On August 9, 2013, CEP announced that it had closed the transactions contemplated by a Contribution Agreement (the “Contribution Agreement”) with Sanchez Energy Partners I, LP  pursuant to which Sanchez agreed to sell to CEP all of the equity of an entity that owns oil and natural gas properties located in Texas and Louisiana in exchange for consideration consisting of 4,724,407 CEP Class B units, 1,130,512 CEP Class A Units, one CEP Class Z Unit and $20,090,876 in cash, for an aggregate purchase price of approximately $30.4 million. CEP also announced that Sanchez, as the holder of a majority of the Company’s Class A Units, removed John R. Collins and Gary M. Pittman as the Company’s Class A managers and elected Antonio R. Sanchez, III and Gary Willinger to the CEP’s Board of Managers to serve as the Class A managers.

On August 30, 2013, Constellation Energy Partners Management, LLC (“CEPM”), a wholly owned subsidiary of the Company, together with Gary M. Pittman and John R. Collins, as Plaintiffs, filed suit in the Delaware Court of Chancery against CEP, CEP’s Chief Executive Officer, Stephen R. Brunner, Richard S. Langdon, Richard H. Bachmann and John N. Seitz, each a member of the five-person CEP Board of Managers, Sanchez Oil & Gas Corporation and Sanchez Energy Partners I, LP (collectively, the “Sanchez Defendants”), Antonio R. Sanchez, III and Gerald F. Willinger, as Defendants (Case No. 8856-VCL).

The lawsuit arises from actions taken by the Defendants prior to and during the August 9, 2013, meeting of the CEP Board of Managers.  Specifically, the lawsuit alleges that the Defendants conspired to dilute CEPM’s ownership interest in CEP and thereby remove CEPM’s right, as the sole owner of Class A units, to select two Managers to the CEP Board of Managers. At the time of the August 9th meeting, Pittman and Collins were serving as CEPM’s duly selected members on the CEP Board of Managers.

The suit asserts that by purporting to issue to the Sanchez Defendants 4,724,407 Class B units and 1,130,512 Class A units in connection with CEP’s purchase of the oil and gas properties, the Defendants acted in bad faith, violated CEP’s Operating Agreement, wrongfully interfered with CEPM’s contractual relations, and breached contractual and fiduciary obligations owed to CEPM. As such, the complaint further alleges that the Sanchez Defendants were without authority to remove Pittman and Collins as the Class A unit representatives on the Board of Managers and purportedly replace them with Defendants Sanchez and Willinger. Among other relief, Plaintiffs seek a declaration that the purported issuance of units to the Sanchez Defendants violates the CEP operating agreement and is therefore invalid and void.  Plaintiffs also seek to have Pittman and Collins reinstated to the CEP Board of Managers. Discovery is currently ongoing. Trial is scheduled in mid-December, 2013.

F-10

POSTROCK ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Note 6 — Asset Retirement Obligations

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

	Nine Months Ended
	September 30,
	2012		2013
Asset retirement obligations at beginning of period (1)	$	10,087	$	10,868
Liabilities incurred		127		277
Liabilities settled		(101)		(41)
Accretion		552		590
Asset retirement obligations at end of period	$	10,665	$	11,694
Current portion of asset retirement obligations	$	—	$	129
Noncurrent portion of asset retirement obligations	$	10,665	$	11,565

____________

(1)Amounts in the table do not include the asset retirement obligations pertaining to KPC, which was divested by the Company during 2012.

Note 7 — Long-Term Debt

The Company has a single credit facility comprised of a $200 million senior secured revolving facility (the “Borrowing Base Facility”) with the following outstanding balances (in thousands):

	December 31,		September 30,
	2012		2013
Borrowing Base Facility	$	57,500	$	86,500
Less current maturities		—		—
Total long-term debt	$	57,500	$	86,500

The borrowing base under the Borrowing Base Facility was redetermined on October 29, 2013, based on reserves at June 30, 2013, to be $115 million, an increase of $20 million from the borrowing base of $95 million at September 30, 2013. With outstanding borrowings of $86.5 million and letters of credit of $1.3 million, $7.2 million was available for additional borrowings at September 30, 2013. The terms of the Borrowing Base Facility are described within Note 10 of Item 8. Financial Statement and Supplementary Data in the 2012 10-K (referenced in the 2012 10-K as the “New Borrowing Base Facility”).

The Company was in compliance with all of its financial covenants under the Borrowing Base Facility at September 30, 2013.

Note 8 — Redeemable Preferred Stock and Warrants

Prior to December 31, 2014, the Company may accrue dividends on its 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 amount of the accrued dividends and additional warrants to purchase shares of PostRock common 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 for dividends paid in kind was $2.9 million during the nine months ended September 30, 2013.

F-11

POSTROCK ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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

			Number of
	Carrying Value of		Outstanding	Liquidation Value of		Number of	Weighted Average
	Series A Preferred		Series A	Series A Preferred		Outstanding	Exercise Price of
	Stock		Preferred Shares	Stock		Warrants	Warrants
December 31, 2012	$	73,152	7,250	$	91,342	34,336,414	$	2.66
Accrued dividends		5,609	—		8,470	5,609,823		1.51
Accretion		2,481	—		—	—		—
September 30, 2013	$	81,242	7,250	$	99,812	39,946,237	$	2.50

Note 9 — Equity and Earnings per Share

Share-Based Payments — The Company recorded share based compensation expense of $463,000 and $618,000 for the three months ended September 30, 2012 and 2013, respectively. Expense was $1.6 million and $2.1 million for the nine months ended September 30, 2012 and 2013, respectively. Total share-based compensation to be recognized on unvested stock awards and options at September 30, 2013, is $2.2 million over a weighted average period of 1.31 years. The following table summarizes option and restricted awards granted during 2013 and their associated valuation assumptions:

		Weighted average
	Number of	fair value per		Weighted average		Weighted average		Weighted
	awards granted	option or share		exercise price		risk free rate		volatility
Options
First quarter 2013 employee awards	490,229	$	0.89	$	1.83	1.0%		64.0%
Second quarter 2013 employee awards	16,970	$	0.84	$	1.47	0.6%		78.4%
Third quarter 2013 employee awards	32,750	$	0.93	$	1.54	1.3%		82.6%
Restricted Stock Awards
First quarter 2013 employee awards	493,438	$	1.83		n/a	n/a	��	n/a
First quarter 2013 director awards	10,243	$	1.47		n/a	n/a		n/a
Second quarter 2013 employee awards	16,879	$	1.47		n/a	n/a		n/a
Second quarter 2013 director awards	40,619	$	1.50		n/a	n/a		n/a
Third quarter 2013 employee awards	23,000	$	1.57		n/a	n/a		n/a
Third quarter 2013 director awards	8,823	$	1.45		n/a	n/a		n/a
Restricted Stock Units
Second quarter 2013 director awards	11,977	$	1.42		n/a	n/a		n/a

F-12

POSTROCK ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Income/(Loss) per Share — A reconciliation of the denominator (number of shares) used in the basic and diluted per share calculations for the periods indicated is as follows:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2012	2013	2012	2013
Denominator for basic earnings per share	14,477,241	25,000,604	12,702,079	24,061,297
Effect of potentially dilutive securities
Unvested share-based awards	—	—	—	—
Warrants	—	—	—	—
Stock options	—	—	—	—
Denominator for diluted earnings per share	14,477,241	25,000,604	12,702,079	24,061,297
Securities excluded from earnings per share calculation
Unvested share-based awards	832,977	—	832,977	—
Antidilutive stock options	1,133,005	2,323,159	1,133,005	2,323,159
Warrants	27,149,235	37,954,117	27,149,235	37,954,117

Common Stock Issuance —The Company has an effective $100 million universal shelf registration statement under which it sold common shares pursuant to an at-the-market issuance sales agreement with a sales agent. During the nine months ended September 30, 2013, the Company sold  2,592,313 common shares for net proceeds of $4.0 million under that program. The at-the-market issuance sales agreement was renewed in August 2013.

The Company issued an additional 126,602 common shares with a fair value of $180,000 as partial payment on a leasehold purchase in May 2013.

Note 10 — 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. The Company currently believes that there are no pending legal proceedings in which it is currently involved which have a reasonable possibility of materially affecting its financial position, results of operations or cash flows in an adverse manner. 

As described in Note 5 — Equity Investment, the Company has filed a lawsuit against CEP, CEP’s Chief Executive Officer, members of CEP’s Board of Managers, Sanchez Oil & Gas Corporation and Sanchez Energy Partners I, LP.

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 nine months ended September 30, 2013, the Company entered into new contractual commitments for software, information technology equipment and services, compressors and office space. It also entered into a sublease of unutilized office space at its corporate headquarters allowing the Company to reduce its future rent expense at that facility. As a result, the $5.8 million 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, 2012.

Other than the contractual commitments discussed above and additional debt borrowings during the nine months ended September 30, 2013, there were no material changes to the Company’s contractual commitments since December 31, 2012.

Note 11 — Profit sharing and deferred compensation plans

401K plan — Substantially all of the Company’s employees are eligible to participate in a profit sharing plan under Section 401(k) of the Internal Revenue Code (the “401K plan”). Prior to 2013, employer matching contributions to the 401K plan were made in cash. Beginning in 2013, employer matching contributions to the 401K plan may be made in Company common stock. In general, the

F-13

POSTROCK ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Company issues common stock to fund its matching contributions although, from time to time, purchases of common stock on the open market by the 401K plan trust may occur if funds are available as a result of forfeitures.  During the nine months ended September 30, 2013,  297,976 shares of common stock were contributed to the 401K plan, of which 218,176 shares were issued by the Company, and 79,800 shares were purchased by the 401K plan trust on the open market.

The following table presents the expense incurred by the Company related to the 401K plan which is reflected in the condensed consolidated statements of operations as a component of general and administrative expense (in thousands):

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2012		2013		2012		2013
401(k) profit sharing plan cost	$	100	$	160	$	317	$	523

Deferred compensation plan — Effective January 1, 2013, the Company established a deferred compensation plan that permits selected employees and members of its board to defer part or all of their eligible compensation. The Company issues common stock into a rabbi trust created to hold the assets associated with the plan. A participant’s deferred compensation is credited with earnings, gains and losses based on the Company’s common stock, the only investment option currently available under the plan. The Company may also make discretionary employer credits in an amount it determines each plan year. Distributions to participants will be made in shares of the Company’s common stock. Company shares held in the rabbi trust are recorded as treasury stock in the condensed consolidated balance sheets. Changes in the fair value of the deferred compensation obligation, currently recorded as a component of paid-in-capital, are not recognized.

The following table presents the number of shares and the related fair values of common stock contributed by the Company to the deferred compensation plan in 2013 ( in thousands except share amounts). The fair value of common stock is based on the market price of the stock on the preceding day that the stock is transferred and thus deemed to be a Level 1 measurement. Under the fair value hierarchy. Contributions were not made in the prior year as the plan was not in effect during that time.

	Three Months Ended		Nine Months Ended
	September 30, 2013		September 30, 2013
Shares of common stock contributed		19,199		279,581
Fair value of common stock contributed	$	31	$	414

Note 12 — Discontinued Operations

In September 2012, the Company consummated the sale of KPC to MV Pipelines, LLC (“MV”) for $53.5 million in cash, $53.4 million after a working capital adjustment. Of this amount, $500,000 was deposited into an escrow account pending acceptable cleanup of a site previously owned by KPC. The cleanup was completed and escrow was released to the Company in January 2013. The operating results of KPC prior to its sale are classified as discontinued operations and are presented separately in the condensed consolidated statements of operations.

F-14

POSTROCK ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The following table presents the results of discontinued operations related to KPC (in thousands):

	Three Months Ended		Nine Months Ended
	September 30, 2012		September 30, 2012
Interstate pipeline revenue	$	2,692	$	8,934
Pipeline expense		(1,178)		(2,825)
Depreciation and amortization		(845)		(2,537)
Loss on disposal of assets (1)		(5,591)		(5,586)
General and administrative expenses		(322)		(945)
Interest expense		—		(45)
Income from discontinued operations before income taxes		(5,244)		(3,004)
Income taxes		—		—
Total income from discontinued operations	$	(5,244)	$	(3,004)

____________

(1)Includes a loss of $5.6 million from the disposal of KPC for the three and nine month periods ended September 30, 2012.

Note 13 — Subsequent Events

On November 1, 2013, the Company closed on two acquisitions of oil and natural gas assets. In the first acquisition, the Company acquired approximately 22,000 net acres of leasehold mineral interests, including certain producing oil and gas properties and related wells and other assets located in Pottawatomie, Cleveland and McClain Counties in central Oklahoma. The total purchase price of the acquired assets was $10.0 million, $10.4 million after certain purchase price adjustments at closing, and consisted of $3.4 million in cash and 4,516,129 shares of PostRock common stock. The Company is in the process of evaluating the fair values of the purchased assets in order to determine the appropriate purchase price allocation. In the second acquisition, the Company acquired a 50% working interest in 110 operated acres and three producing wells from one of its working interest partners in Seminole County, Oklahoma, for $750,000 in cash.

F-15

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

Overview

We are an independent oil and gas company engaged in the acquisition, exploration, development, production and gathering of crude oil and natural gas. Our primary production activity is focused in the Cherokee Basin, a 15-county region in southeastern Kansas and northeastern Oklahoma. We also have oil producing properties in Oklahoma and minor oil and gas producing properties in the Appalachian Basin. We previously owned an interstate natural gas pipeline which was sold in September 2012 and we report its results as a discontinued operation in our financial statements. Unless the context requires otherwise, references to “PostRock,” the “Company,” “we,” “us” and “our” refer to PostRock Energy Corporation and its consolidated subsidiaries.

The following discussion should be read together with the unaudited condensed consolidated financial statements and related notes included elsewhere herein and with our annual report on Form 10-K for the year ended December 31, 2012.

2013 Drilling Program and Production Update

During the first nine months of 2013, we completed 151 new oil wells and recompleted 62 wells in the Cherokee Basin, completed three new wells and recompleted seven wells in Central Oklahoma, and recompleted a well in the Appalachian Basin. Capital spending during the nine months ended September 30, 2013, totaled $45.1 million. Of this amount, $33.4 million was spent on oil directed drilling, recompletions and related infrastructure while $6.4 million was spent on maintenance related projects primarily related to compressor optimization. An additional $5.3 million was spent on increasing Central Oklahoma acreage and lease extensions in the Cherokee Basin. As a result of our oil-focused development, net oil sales averaged 592 barrels a day in the third quarter, a 117.5% increase over the prior-year quarter and a 8.8% increase over the second quarter of 2013. Increased revenues from oil along with a modest improvement in natural gas prices have enabled us to grow revenues by 37.8% compared to the prior year quarter.

Our focus will continue to be towards growing oil production and reserves as the returns on these efforts are expected to exceed those of gas projects. This transition is a significant contributing factor to our 12% decline in gas and 102% increase in oil sales volumes when comparing the nine month periods ended September 30, 2012 and 2013.

Central Oklahoma Property Acquisition

On November 1, 2013, we closed on two acquisitions of oil and natural gas assets. In the first acquisition, we acquired approximately 22,000 net acres of leasehold mineral interests, including certain producing oil and gas properties and related wells and other assets located in Pottawatomie, Cleveland and McClain Counties in Central Oklahoma. The total purchase price of the acquired assets was $10.0 million, $10.4 million after certain purchase price adjustments at closing, and consisted of $3.4 million in cash and 4,516,129 shares of PostRock common stock. The acquisition had an effective date of July 1, 2013. Approximately 9,000 of the 22,000 net acres are held by production. At the time of the announced purchase on October 14, 2013, production approximated 50 net barrels of oil equivalent (“BOE”) per day. We estimate that the net proved reserves being acquired total 574,000 BOE, of which 95% is oil and 60% is classified as developed. 

In the second acquisition, we acquired a 50% working interest in 110 operated acres and three producing wells in Seminole County, Oklahoma, for $750,000 in cash.  We estimate that the net proved reserves being acquired total 110,000 barrels of oil, of which 40% is classified as developed.

1

Three Months Ended September 30, 2012 Compared to the Three Months Ended September 30, 2013

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

	Three Months Ended
	September 30,				Increase/
	2012		2013		(Decrease)
	($ in thousands except per unit data)
Natural gas sales	$	10,819	$	12,426	$	1,607	14.9%
Crude oil sales	$	2,232	$	5,552	$	3,320	148.7%
Gathering revenue	$	646	$	636	$	(10)	(1.5%)
Production expense	$	9,917	$	9,983	$	66	0.7%
Depreciation, depletion and amortization	$	7,321	$	6,957	$	(364)	(5.0%)
Impairment of oil and gas assets	$	4,309	$	—	$	(4,309)	(100.0%)
Gain (loss) on disposal of assets	$	(64)	$	159	$	223	*
Sales Data
Oil sales (Bbls)		25,035		54,439		29,404	117.5%
Natural gas sales (Mmcf)		4,025		3,640		(385)	(9.6%)
Total sales (Mmcfe)		4,176		3,966		(210)	(5.0%)
Average daily sales (Mmcfe/d)		45.4		43.1		(2.3)	(5.0%)
Average Sales Price per Unit
Natural Gas (Mcf)	$	2.69	$	3.41	$	0.72	26.8%
Oil(Bbl)	$	89.15	$	101.99	$	12.84	14.4%
Natural Gas Equivalent (Mcfe)	$	3.13	$	4.53	$	1.40	44.7%
Average Unit Costs per Mcfe
Production expense	$	2.38	$	2.52	$	0.14	5.9%
Depreciation, depletion and amortization	$	1.75	$	1.75	$	—	0.0%

____________

* Not meaningful

Natural gas sales increased $1.6 million, or 14.9%, from $10.8 million during the three months ended September 30, 2012, to $12.4 million during the three months ended September 30, 2013. Higher natural gas prices resulted in increased revenues of $2.6 million while lower gas volumes partially offset that increase by $1.0 million. The decline in gas volumes resulted from the lack of gas development projects in the last 24 months as gas prices continue to be at uneconomic levels. Our average realized natural gas price increased from $2.69 per Mcf for the three months ended September 30, 2012, to $3.41 per Mcf for the three months ended September 30, 2013.

Oil revenue increased $3.3 million, or 148.7%, from $2.2 million during the three months ended September 30, 2012, to $5.6 million during the three months ended September 30, 2013. Higher oil volumes resulted in increased revenues of $2.6 million while higher oil prices increased revenue by an additional $699,000. Our oil production has grown as a result of development activities that have focused on expanding oil production and reserves since mid 2012. Our average realized oil price increased from $89.15 per barrel for the three months ended September 30, 2012, to $101.99 per barrel for the three months ended September 30, 2013.

Gathering revenue remained relatively flat at  $646,000 for the three months ended September 30, 2012,  compared to  $636,000 for the three months ended September 30, 2013.  The decrease in gas volumes being transported was offset by an increase in pricing.

Production expense consists of lease operating expenses, severance and ad valorem taxes (“production taxes”) and gathering expense. Production expense increased by  $66,000, or 0.7 %, from $9.9 million during the three months ended September 30, 2012, to $10.0 million during the three months ended September 30, 2013.  Increased costs associated with water handling were mostly offset by $379,000 in reduced compressor rental costs and $59,000 lower production taxes. As a result of lower volumes, production expense increased from $2.38 per Mcfe for the three months ended September 30, 2012, to $2.52 per Mcfe for the three months ended September 30, 2013.  

Depreciation, depletion and amortization decreased $364,000, or 5.0%, from $7.3 million during the three months ended September 30, 2012, to $7.0 million during the three months ended September 30, 2013. The decrease was primarily the result of lower volumes

2

produced. On a per unit basis, depreciation, depletion and amortization was unchanged at $1.75 per Mcfe during the three months ended September 30, 2012 and 2013.

General and administrative expenses were relatively flat at $3.5 million during the three months ended September 30, 2012 and 2013.  Increases in legal expenses, stock compensation and benefits were offset by one-time severance charges of $435,000 associated with our Oklahoma City office restructuring in September 2012. Legal expenses were $237,000 higher than the prior year quarter primarily due to our litigation with Constellation Energy Partners LLC (“CEP”).

Other income (expense) consists primarily of realized and unrealized gains or losses from derivative instruments, gain or loss from equity investment and net interest expense. We recorded a realized gain on our derivative contracts of $2.7 million for the three months ended September 30, 2012, compared to a realized loss of $145,000 for the three months ended September 30, 2013. The current quarter losses on our Southern Star Basis swaps and NYMEX crude oil swaps were partially offset by gains on our NYMEX natural gas swaps. As a result of lower contract prices on our outstanding natural gas swaps as well as the early settlement of 2013 hedges in the prior year, we expect realized gains on our commodity derivatives to be lower for 2013 compared to 2012. We recorded an unrealized loss from derivative instruments of $6.5 million and an unrealized gain of $1.3  million for the three months ended September 30, 2012 and 2013, respectively. We recorded a mark-to-market loss of $2.1 million and a mark-to-market gain of $740,000 on our equity investment in CEP for the three months ended September 30, 2012 and 2013, respectively. CEP’s Class B unit price increased 14% from $1.88 per unit at the end of the second quarter of 2013 to $2.14 per unit at the end of the third quarter of 2013.  This increase resulted in a mark-to-market gain on our investment in CEP’s Class B units of approximately $1.5 million. Also during the quarter, CEP issued additional Class A Units, resulting in a mark-to-market loss on our investment in CEP’s Class A Units of $799,000. Interest expense, net, was $2.6 million during the three months ended September 30, 2012, and $883,000 during the three months ended September 30, 2013. Interest was lower as a result of reduced debt. 

Nine Months Ended September 30, 2012 Compared to the Nine Months Ended September 30,2013

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

	Nine Months Ended
	September 30,				Increase/
	2012		2013		(Decrease)
	($ in thousands except per unit data)
Natural gas sales	$	31,069	$	39,302	$	8,233	26.5%
Crude oil sales	$	6,254	$	12,953	$	6,699	107.1%
Gathering revenue	$	1,819	$	2,006	$	187	10.3%
Production expense	$	32,117	$	30,460	$	(1,657)	(5.2%)
Depreciation, depletion and amortization	$	20,423	$	20,078	$	(345)	(1.7%)
Impairment of oil and gas assets	$	4,309	$	—	$	(4,309)	(100.0%)
Gain (loss) on disposal of assets	$	(226)	$	169	$	395	*
Sales Data
Oil sales (Bbls)		67,772		136,599		68,827	101.6%
Natural gas sales (Mmcf)		12,454		10,995		(1,459)	(11.7%)
Total sales (Mmcfe)		12,861		11,815		(1,046)	(8.1%)
Average daily sales (Mmcfe/d)		46.9		43.3		(3.6)	(7.7%)
Average Sales Price per Unit
Natural Gas (Mcf)	$	2.49	$	3.57	$	1.08	43.4%
Oil(Bbl)	$	92.28	$	94.83	$	2.55	2.8%
Natural Gas Equivalent (Mcfe)	$	2.90	$	4.42	$	1.52	52.4%
Average Unit Costs per Mcfe
Production expense	$	2.50	$	2.58	$	0.08	3.2%
Depreciation, depletion and amortization	$	1.59	$	1.70	$	0.11	6.9%

____________

* Not meaningful

Natural gas sales increased $8.2 million, or 26.5 %, from $31.1 million during the nine months ended September 30, 2012, to $39.3 million during the nine months ended September 30, 2013. Higher natural gas prices resulted in increased revenues of $11.9 million

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while lower gas volumes partially offset that increase by $3.7 million. The decline in gas volumes resulted from the lack of gas development projects in the last 24 months as gas prices continue to be at uneconomic levels. Our average realized natural gas price increased from $2.49 per Mcf for the nine months ended September 30, 2012, to $3.57 per Mcf for the nine months ended September 30, 2013.

Oil revenue increased $6.7 million, or 107.1 %, from $6.3 million during the nine months ended September 30, 2012, to $13.0 million during the nine months ended September 30, 2013. Higher oil volumes resulted in increased revenues of $6.4 million while higher oil prices provided an additional increase of $348,000. Our average realized oil price increased from $92.28 per barrel for the nine months ended September 30, 2012, to $94.83 per barrel for the nine months ended September 30, 2013.

Gathering revenue increased $187,000, or 10.3%, from $1.8 million for the nine months ended September 30, 2012, to $2.0 million for the nine months ended September 30, 2013. The increase was primarily due to higher realized prices but partially offset by a decrease in gas volumes being transported.

Production expense decreased $1.7 million, or 5.2 %, from $32.1 million for the nine months ended September 30, 2012, to $30.5 million for the nine months ended September 30, 2013.  Lower costs on repairs and maintenance of $622,000, compressor rentals of $490,000 and reductions in other operational areas were partially offset by higher production taxes of $334,000 and higher water handling costs. As a result of lower volumes, production expense increased from $2.50 per Mcfe for the nine months ended September 30, 2012, to $2.58 per Mcfe for the nine months ended September 30, 2013.

Depreciation, depletion and amortization was relatively flat at $20.4 million for the nine months ended September 30, 2012,  compared to  $20.1 million for the nine months ended September 30, 2013. Higher depreciation rates in the current period were offset by lower volumes and lower depreciation on equipment. On a per unit basis, we had an increase of $0.11 per Mcfe from $1.59 per Mcfe during the nine months ended September 30, 2012, to $1.70 per Mcfe during the nine months ended September 30, 2013.  

General and administrative expenses were relatively flat at $11.3 million for the nine months ended September 30, 2012 and 2013. The 2012 period included a $435,000 severance charge for the restructuring of our Oklahoma City office while the 2013 period included a $528,000 charge resulting from a 2009 workman’s compensation insurance audit. Excluding these charges, general and administrative expenses would have been $167,000 lower in the current year period compared to the prior year period. Higher stock compensation, incentive compensation and benefits of $1.1 million were more than offset by $1.3 million in cost reductions from wages, legal fees, contract labor and capitalized expenses.

Other income (expense) consists primarily of realized and unrealized gains or losses from derivative instruments, gain or loss from equity investment, net interest expense and acquisition costs. We recorded a realized gain on our derivative contracts of $33.4 million for the nine months ended September 30, 2012, compared to a realized loss of $2.3 million for the nine months ended September 30, 2013.  Realized losses on our Southern Star Basis swaps were partially offset by gains on our NYMEX crude oil and natural gas swaps. We recorded an unrealized loss from derivative instruments of $25.4 million and an unrealized gain of $5.2 million for the nine months ended September 30, 2012 and 2013, respectively. We recorded a mark-to-market loss of $4.6 million and a mark-to-market gain of $5.2 million on our equity investment in CEP for the nine months ended September 30, 2012 and 2013, respectively.Gain on forgiveness of debt was $255,000 for the nine months ended September 30, 2012. Interest expense, net, was $7.8 million during the nine months ended September 30, 2012, and $2.3 million during the nine months ended September 30, 2013. Interest was lower as a result of reduced debt. 

Liquidity and Capital Resources

Cash flows from operating activities have historically been driven by the quantities of our production and the prices received from the sale of our production. 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. Proceeds from or payments for derivative settlements are included in cash flows from operations. Cash expenses also impact our operating cash flow and consist primarily of production expenses, interest on our indebtedness and general and administrative expenses.

Our primary sources of liquidity for the nine months ended September 30, 2013, were borrowings under our borrowing base credit facility, cash from operations and proceeds from issuing common stock. At September 30, 2013, our debt increased by $29.0 million from December 31, 2012.  The increase was primarily due to borrowings to fund capital expenditures. Also contributing to the increase was a $4.5 million royalty settlement payment, which was made in December 2012 and funded in early 2013, as well as other working capital needs.

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Cash Flows from Operating Activities

Cash flows provided by operating activities was $29.4 million for the nine months ended September 30, 2012, compared to $8.9 million for the nine months ended September 30, 2013.  The decrease in cash was primarily a result of a decrease in realized gains from commodity derivatives where $30.4 million in realized gains were generated in the prior year period compared to $2.3 million in realized losses in the current period. The decrease in cash from our derivatives was partially offset by increases in revenue and a reduction in interest expense.

Cash Flows from Investing Activities

Cash flows provided by investing activities were $40.9 million for the nine months ended September 30, 2012, compared to cash used of $41.7 million for the nine months ended September 30, 2013.  The increased outflow was primarily due to higher capital expenditures in the current period as well as the sale of our interstate pipeline in the prior period. Capital expenditures increased from $12.7 million, including non-cash items, during the nine months ended September 30, 2012, to $45.1 million, including non-cash items, during the nine months ended September 30, 2013. Capital expenditures in the prior year period were lower compared to the current period as result of the steep decline in natural gas prices in early 2012 which prompted us to curtail gas related projects early in the year and begin identifying viable oil development projects. Capital expenditures in the current year reflect our expanded oil development activities in the Cherokee Basin and Central Oklahoma and our efforts to increase oil-targeted leasehold acreage.  In September 2012, we closed on the sale of our interstate pipeline and received cash proceeds of $53.4 million. During the nine months ended September 30, 2013, restrictions on $1.5 million of cash were lifted as we moved letters of credit from our previous lender to our current borrowing base credit facility. The following table sets forth our capital expenditures, including costs we have incurred but not paid, by major categories for the nine months ended September 30, 2013 (in thousands):

	Nine Months Ended
	September 30, 2013
Capital expenditures
Leasehold acquisition	$	5,322
Development		33,359
Other items		6,405
Total capital expenditures	$	45,086

Cash Flows from Financing Activities

Cash flows used in financing activities were $70.5 million for the nine months ended September 30, 2012, as compared to cash received of $32.6 million for the nine months ended September 30, 2013. The difference in cash flows was primarily driven by debt repayments in the prior year compared to borrowings in the current year. Debt repayments were $90.1 million for the nine months ended September 30, 2012, compared to borrowings of $29.0 million for the nine months ended September 30, 2013. The repayments in 2012 were facilitated by proceeds from the sale of our interstate pipeline and the issuance of equity to White Deer Energy. During the nine months ended September  30, 2012,  we issued $13.5 million of common stock and $6.0 million of preferred stock and warrants to White Deer. During the nine months ended September  30, 2013, we issued $4.1 million of common stock under our at-the-market sales agreement, as discussed below.

Sources of Liquidity in 2013 and Capital Requirements

We rely on our cash flows from operating activities as a source of internally generated liquidity. 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 depressed natural gas prices in 2012 which have since begun a modest rebound in 2013. To a lesser extent, we have in the past relied on the sale of our non-core assets to generate liquidity. During 2010 and 2011, we sold non-core assets in the Appalachian Basin generating proceeds of $44.6 million. In September 2012, we sold our interstate pipeline for $53.4 million net after a working capital adjustment. From time to time, we may also issue equity as an external source of liquidity. During 2012, we generated gross proceeds of $32.5 million from issuing equity to White Deer and $724,000 from sales of common stock under our at-the-market sales program. During 2013, we generated an additional $4.1 million from common stock sales under our at-the-market sales program. Our recent acquisition of oil and gas properties in Central Oklahoma, which closed on November 1, 2013, was partially funded by issuing 4,516,129 shares of our common stock. The proceeds from the sale of our non-core assets and from equity issuances have generally been utilized to repay outstanding debt, fund our development program, fund asset acquisitions and for working capital purposes.

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At September 30, 2013, we had a $200 million secured borrowing base revolving credit facility with a borrowing base of $95 million (the “Borrowing Base Facility”). We rely on this facility as an external source of long and short-term liquidity. The terms of this facility are described within Note 10 of Item 8. Financial Statement and Supplementary Data in our Annual Report on Form 10-K for the year ended December 31, 2012 (referenced in the document as the “New Borrowing Base Facility”).

The borrowing base under our Borrowing Base Facility was redetermined on October 29, 2013, based on reserves at June 30, 2013, to be $115 million, an increase of $20 million. The borrowing base is determined based on the value of our oil and natural gas reserves at our lenders’ forward price forecasts, which are generally derived from futures prices. The redetermination was also adjusted to reflect our recent acquisition of oil and gas properties in Central Oklahoma. At November 5, 2013, with borrowings of $95.0 million and $1.3 million in outstanding letters of credit, we had $18.7 million available under the facility. With the current availability under our Borrowing Base Facility and expected cash flows from operations, we believe that we have sufficient liquidity to fund our capital expenditures and financial obligations for the next 12 months.

We have an effective universal shelf registration statement on Form S-3. Pursuant to the registration statement, we implemented an at-the-market program under which shares of our common stock were sold. During the nine months ended September 30, 2013, we sold 2,592,313 shares of common stock under the program for $4.0 million, net of $115,000 in agent commissions. We renewed our at-the-market program in late August 2013. There were no sales of common stock in the third quarter.

Dilution

At September 30, 2013, including 9,834,620 shares of our common stock held by White Deer, we had 24,636,051 shares of common stock outstanding. In addition, we had 40,170,845 outstanding warrants to purchase our common stock of which 39,946,237 are owned by White Deer at an average exercise price of $2.50 and 224,608 are owned by Constellation Energy Group Inc. at an average exercise price of $7.57. We also had 192,351 restricted stock units and 2,323,159 options outstanding granted under our long-term incentive plan. Consequently, if these securities were included as outstanding, our outstanding shares would have been 67,322,406 of which the warrants and common stock owned by White Deer would represent approximately 74 %. 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 nine months ended September 30, 2013,  we entered into new contractual commitments for software, information technology equipment and services, compressors and office space. We also entered into a sublease of unutilized office space at our corporate headquarters allowing us to reduce future rent expense for that facility. As a result, the $5.8 million minimum amount of these contracts over a span of five years would be an increase to the amount included in our outstanding contractual commitments table at December 31, 2012.

Other than the contractual commitments discussed above and additional debt borrowings during the nine months ended September 30, 2013, there were no material changes to the our contractual commitments since December 31, 2012.

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:

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•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, 2012, 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, 2012, is available on our website at www.pstr.com.

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

The following table summarizes the estimated volumes, fixed prices and fair value attributable to our oil and gas derivative contracts at September 30, 2013.

	Remainder of		Year Ending December 31,
	2013		2014		2015		2016		Total
	($ in thousands, except per unit data)
Natural Gas Swaps
Contract volumes (Mmbtu)		2,903,679		10,327,572		8,983,560		7,814,028		30,028,839
Weighted-average fixed price per Mmbtu	$	4.01	$	4.01	$	4.01	$	4.01	$	4.01
Fair value, net	$	1,193	$	1,530	$	(402)	$	(1,121)	$	1,200
Natural Gas Basis Swaps
Contract volumes (Mmbtu)		2,268,494		—		—		—		2,268,494
Weighted-average fixed price per Mmbtu	$	(0.75)	$	—	$	—	$	—	$	(0.75)
Fair value, net	$	(1,223)	$	—	$	—	$	—	$	(1,223)
Crude Oil Swaps
Contract volumes (Bbl)		28,854		116,076		71,568		65,568		282,066
Weighted-average fixed price per Bbl	$	99.76	$	95.19	$	92.73	$	90.33	$	93.90
Fair value, net	$	(52)	$	(22)	$	280	$	318	$	524
Total fair value, net	$	(82)	$	1,508	$	(122)	$	(803)	$	501

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,

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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 September 30, 2013. Based on that evaluation, our principal executive officer and principal financial officer concluded that, as of September 30, 2013, our disclosure controls and procedures were effective with respect to the recording, processing, summarizing and reporting, within the time periods specified in the SEC’s rules and forms, of information required to be disclosed by us in the reports that we file or submit under the Exchange Act.

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

PART II — OTHER INFORMATION

ITEM 1A. RISK FACTORS.

For additional information about our risk factors, see Item 1A. “Risk Factors” in our 2012 10-K.

ITEM 6. EXHIBITS

1.1	Amendment No. 1, dated August 23, 2013, to At-The-Market Issuance Sales Agreement, dated August 23, 2011, between PostRock Energy Corporation and MLV & Co. LLC (formerly McNicoll, Lewis & Vlak LLC), as agent (incorporated herein by reference to Exhibit 1.1 to PostRock’s Current Report on Form 8-K filed on August 23, 2013).
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.

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

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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 6th day of November 2013.

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

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