PostRock Energy (PSTR) 10-Q 2014 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, 2014

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 ☒ 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 ☒ 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	☒

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

At August 1, 2014, there were 30,801,884 outstanding shares of the registrant’s common stock having an aggregate market value of $40.0 million based on a closing price of $1.30 per share.

POSTROCK ENERGY CORPORATION

FORM 10-Q

FOR THE QUARTER ENDED JUNE 30, 2014

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’ 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	6
Item 4.	Controls and Procedures	7
	PART II — OTHER INFORMATION
Item 1A.	Risk Factors	7
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	7
Item 6.	Exhibits	8
SIGNATURES		9

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,		June 30,
	2013		2014
			(Unaudited)
ASSETS
Current assets
Cash and equivalents	$	37	$	—
Restricted cash		—		56
Accounts receivable—trade, net		7,722		8,138
Other receivables		194		658
Inventory		886		961
Other		820		1,291
Derivative financial instruments		54		—
Total		9,713		11,104
Oil and natural gas properties, full cost method of accounting, net		141,911		146,236
Other property and equipment, net		14,180		13,142
Investment, net		14,588		4,979
Derivative financial instruments		652		—
Other, net		2,038		1,789
Total assets	$	183,082	$	177,250
LIABILITIES AND STOCKHOLDERS’ DEFICIT
Current liabilities
Accounts payable	$	7,406	$	7,984
Revenue payable		4,397		4,542
Accrued expenses and other		4,055		3,830
Derivative financial instruments		1,937		4,186
Total		17,795		20,542
Derivative financial instruments		1,796		2,343
Long-term debt		92,000		87,000
Mandatorily redeemable preferred stock—6,000 shares issued and outstanding		64,523		65,345
Asset retirement obligations		13,099		13,531
Other		75		—
Total liabilities		189,288		188,761
Commitments and contingencies
Series A Cumulative Redeemable Preferred Stock, $0.01 par value; 1,250 shares issued and outstanding		23,828		28,643
Stockholders’ deficit
Preferred stock, $0.01 par value; 5,000,000 authorized shares; 113,521 and 153,335 shares of Series B Voting Preferred Stock issued and outstanding, respectively		1		2
Common stock, $0.01 par value; 100,000,000 authorized shares; issued—29,915,951 and 32,644,318; outstanding—29,556,263 and 30,777,181, respectively		299		326
Additional paid-in capital		397,170		401,269
Treasury stock, at cost; 359,688 and 1,867,137 shares, respectively		(512)		(2,448)
Accumulated deficit		(426,992)		(439,303)
Total stockholders’ deficit		(30,034)		(40,154)
Total liabilities and stockholders’ deficit	$	183,082	$	177,250

The accompanying notes are an integral part of these statements.

F-1

POSTROCK ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2014		2013		2014
	(in thousands, except per share data)
Revenues
Natural gas sales	$	14,434	$	14,656	$	26,876	$	30,619
Crude oil sales		4,444		6,194		7,401		11,299
Gathering		716		746		1,370		1,481
Total		19,594		21,596		35,647		43,399
Costs and expenses
Production		10,702		10,564		20,477		20,836
General and administrative		4,259		3,499		7,805		7,410
Depreciation, depletion and amortization		6,693		7,357		13,121		14,259
Gain on disposal of assets		(41)		(59)		(10)		(78)
Acquisition costs		—		13		—		47
Total		21,613		21,374		41,393		42,474
Operating income (loss)		(2,019)		222		(5,746)		925
Other income (expense)
Realized loss from derivative financial instruments		(1,330)		(1,925)		(2,203)		(4,432)
Unrealized gain (loss) from derivative financial instruments		10,128		(894)		3,880		(3,502)
Gain on investment		863		87		4,445		1,706
Other income, net		7		5		20		5
Interest expense, net		(769)		(3,483)		(1,410)		(7,013)
Total		8,899		(6,210)		4,732		(13,236)
Income (loss) before income taxes		6,880		(5,988)		(1,014)		(12,311)
Income taxes		—		—		—		—
Net income (loss)		6,880		(5,988)		(1,014)		(12,311)
Preferred stock dividends		(2,823)		(1,021)		(5,563)		(1,950)
Accretion of redeemable preferred stock		(826)		(436)		(1,604)		(806)
Net income (loss) attributable to common stockholders	$	3,231	$	(7,445)	$	(8,181)	$	(15,067)
Net loss per common share
Basic loss per share	$	0.13	$	(0.23)	$	(0.35)	$	(0.48)
Diluted loss per share	$	0.13	$	(0.23)	$	(0.35)	$	(0.48)
Weighted average common shares outstanding
Basic		24,395		31,799		23,584		31,409
Diluted		24,509		31,799		23,584		31,409

The accompanying notes are an integral part of these statements.

F-2

POSTROCK ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended June 30,
	2013		2014
	(in thousands)
Cash flows from operating activities
Net loss	$	(1,014)	$	(12,311)
Adjustments to reconcile net loss to net cash flows from (used in) operating activities
Depreciation, depletion and amortization		13,121		14,259
Share-based and other compensation		2,141		1,921
Amortization of deferred loan costs		215		260
Change in fair value of derivative financial instruments		(3,880)		3,502
Gain on disposal of assets		(10)		(78)
Gain on investment		(4,445)		(1,706)
Other non-cash changes to items affecting net loss		—		5,133
Changes in operating assets and liabilities
Accounts receivable		(768)		(416)
Accounts payable		(4,507)		(1,464)
Other		396		(649)
Net cash flows from operating activities		1,249		8,451
Cash flows from investing activities
Restricted cash		1,500		(56)
Proceeds from sale of securities		—		10,778
Expenditures for equipment, development and leasehold		(26,821)		(14,737)
Proceeds from sale of assets		194		538
Net cash flows used in investing activities		(25,127)		(3,477)
Cash flows from financing activities
Proceeds from debt		20,000		36,000
Repayments of debt		—		(41,000)
Debt and equity financing costs		(454)		(11)
Proceeds from issuance of common stock		4,075		—
Net cash flows from (used in) financing activities		23,621		(5,011)
Net decrease in cash and cash equivalents		(257)		(37)
Cash and equivalents beginning of period		525		37
Cash and equivalents end of period	$	268	$	—

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, 2013 are unaudited)

		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
	(in thousands, except share data)
Balance, December 31, 2013	113,521	$	1	29,915,951	$	299	$	397,170	359,688	$	(512)	$	(426,992)	$	(30,034)
Stock-based compensation	—		—	—		—		346	—		—		—		346
Restricted stock grants, net of forfeitures	—		—	286,002		3		(2)	94,454		(119)		—		(118)
Funding of 401K and deferred compensation plans	—		—	1,716,559		17		3,373	1,412,995		(1,817)		—		1,573
Issuance of Series B preferred stock	39,814		1	—		—		—	—		—		—		1
Issuance of warrants	—		—	—		—		2,252	—		—		—		2,252
Issuance of common stock, net	—		—	725,806		7		886	—		—		—		893
Preferred stock dividends	—		—	—		—		(1,950)	—		—		—		(1,950)
Preferred stock accretion	—		—	—		—		(806)	—		—		—		(806)
Net loss	—		—	—		—		—	—		—		(12,311)		(12,311)
Balance, June 30, 2014	153,335	$	2	32,644,318	$	326	$	401,269	1,867,137	$	(2,448)	$	(439,303)	$	(40,154)

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, and in Central Oklahoma. It also has minor oil and gas producing properties in the Appalachian Basin. 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 note 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, 2013 (the “2013 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.

Note 2 — Other Balance Sheet Items

Components of the condensed consolidated balance sheet items are described below:

	December 31,		June 30,
	2013		2014
	(in thousands)
Other current assets
Prepaid fees and deposits	$	820	$	1,291
Total	$	820	$	1,291
Other noncurrent assets, net
Deferred financing costs	$	1,547	$	1,299
Noncurrent deposits and other		491		490
Total	$	2,038	$	1,789
Accrued expenses and other
Interest	$	39	$	55
Employee-related costs and benefits		1,062		1,014
Non-income related taxes		72		1,532
Fees for services		1,127		175
Asset retirement obligations		129		134
Current income taxes		80		—
Other		1,546		920
Total	$	4,055	$	3,830
Other noncurrent liabilities
Lease termination costs	$	75	$	—
Total	$	75	$	—

F-5

POSTROCK ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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 oil and 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.

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 include transferring its position to another counterparty or requesting 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 June 30, 2014, the Company was a net obligor with respect to outstanding derivative contracts with both of its counterparties; therefore, the Company 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:

		December 31,		June 30,
Derivative Financial Instruments	Balance Sheet location	2013		2014
		(in thousands)
Commodity contracts	Current derivative financial instrument asset	$	54	$	—
Commodity contracts	Long-term derivative financial instrument asset		652		—
Commodity contracts	Current derivative financial instrument liability		(1,937)		(4,186)
Commodity contracts	Long-term derivative financial instrument liability		(1,796)		(2,343)
		$	(3,027)	$	(6,529)

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2014		2013		2014
	(in thousands)
Realized losses	$	(1,330)	$	(1,925)	$	(2,203)	$	(4,432)
Unrealized gains (losses)		10,128		(894)		3,880		(3,502)
Total gain (loss) from derivative financial instruments	$	8,798	$	(2,819)	$	1,677	$	(7,934)

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-6

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.  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,		June 30,
	2013		2014
	(in thousands)
Derivative Assets
Gross amounts of recognized assets	$	706	$	—
Gross amounts offset in the balance sheet		—		—
Net amounts of assets presented in the balance sheet		706		—
Gross amounts not offset in the balance sheet		(706)		—
Net amount	$	—	$	—
Derivative Liabilities
Gross amounts of recognized liabilities	$	3,733	$	6,529
Gross amounts offset in the balance sheet		—		—
Net amounts of liabilities presented in the balance sheet		3,733		6,529
Gross amounts not offset in the balance sheet		(706)		—
Net amount	$	3,027	$	6,529

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, 2014.

	Remainder of		Year Ending December 31,
	2014		2015		2016		Total
	($ in thousands, except per unit data)
Natural Gas Swaps
Contract volumes (MMBtu)		5,163,786		8,983,560		7,814,028		21,961,374
Weighted-average fixed price per MMBtu	$	4.01	$	4.01	$	4.01	$	4.01
Fair value, net	$	(2,285)	$	(1,818)	$	(1,623)	$	(5,726)
Crude Oil Swaps
Contract volumes (Bbl)		58,038		71,568		65,568		195,174
Weighted-average fixed price per Bbl	$	95.19	$	92.73	$	90.33	$	92.65
Fair value, net	$	(458)	$	(279)	$	(66)	$	(803)
Total fair value, net	$	(2,743)	$	(2,097)	$	(1,689)	$	(6,529)

Note 4 — Fair Value Measurements

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

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

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

F-7

POSTROCK ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Investment — The Company has an investment in Constellation Energy Partners LLC (“CEP”), which consisted of 4,282,500 Class B units at June 30, 2014 (see Note 5 —  Investment).  Fair value for the Class B units, which are publicly traded, is based on market price and classified as a Level 1 measurement under the fair value hierarchy. At June 30, 2014, the fair value used for the Class B units was $2.66 per unit. At December 31, 2013, the Company also held 484,505 of Class A units. Fair value for the Company’s Class A units was classified as a Level 2 measurement. As of March 31, 2014, the Company no longer held any Class A units (see Note 5 —  Investment).

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:

							Total Net Fair
	Level 1		Level 2		Level 3		Value
	(in thousands)
At December 31, 2013
Investment, gross	$	14,205	$	383	$	—	$	14,588
Derivative financial instruments—assets		—		706		—		706
Derivative financial instruments—liabilities		—		(3,733)		—		(3,733)
Total	$	14,205	$	(2,644)	$	—	$	11,561
At June 30, 2014
Investment, gross	$	11,392	$	—	$	—	$	11,392
Derivative financial instruments—assets		—		—		—		—
Derivative financial instruments—liabilities		—		(6,529)		—		(6,529)
Total	$	11,392	$	(6,529)	$	—	$	4,863

There were no movements between Levels 1 and 2 during the six months ended June 30, 2014. The Company has not owned any Level 3 assets or liabilities since 2012.

Additional Fair Value Disclosures — The Company had 7,250 outstanding shares of Series A Cumulative Redeemable Preferred Stock (“Series A Preferred Stock”) (see Note 8 — Redeemable Preferred Stock and Warrants) at June 30, 2014. The obligation to redeem the preferred shares is reflected as debt (“mandatorily redeemable preferred stock”) and temporary equity (“Series A Cumulative Redeemable Preferred Stock”) in the condensed balance sheet (see Note 8 — Redeemable Preferred Stock and Warrants). The fair value and the carrying value of these securities at December 31, 2013 were $30.9 million and $23.8 million, respectively, for the portion reflected as temporary equity and $71.9 million and $64.5 million, respectively, for the portion reflected as debt. The fair value and carrying value of these securities at June 30, 2014 were $37.2 million and $28.6 million, respectively, for the portion reflected as temporary equity and $71.9 million and $65.3 million, respectively, for the portion reflected in debt. 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 12.9% and 7.3% at December 31, 2013 and June 30, 2014, respectively, which were 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 — Investment

The Company elected the fair value option to account for its interest in CEP at inception. 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. While the Company no longer has the ability to exercise significant influence over CEP, it will continue to use the fair value option to account for such investment as that election is irrevocable. See further discussion below on the sale of CEP units.

F-8

POSTROCK ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The following table presents the mark-to-market gains on the Company’s investment (recorded as a component of other income in the condensed consolidated statements of operations):

	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2014		2013		2014
	(in thousands)
Mark-to-market gains on investment	$	863	$	87	$	4,445	$	1,706

The following table presents the Company’s investment in CEP at gross fair value, and the valuation allowance on CEP investment, which includes certain proceeds received from the settlement agreement as described below (presented net in the consolidated balance sheets):

	December 31,		June 30,
	2013		2014
	(in thousands)
Investment, at gross fair value	$	14,588	$	11,392
Valuation allowance on investment		—		(6,413)

On March 31, 2014, PostRock Energy Corporation and its wholly owned subsidiary, Constellation Energy Partners Management, LLC (“CEPM”), entered into a settlement agreement fully resolving all claims associated with the lawsuit filed August 30, 2013 against CEP, CEP’s Chief Executive Officer, members of CEP’s Board of Managers, Sanchez Oil & Gas Corporation and Sanchez Energy Partners I, LP (“SEPI”).

Under the settlement agreement, CEPM is to recover a target amount of $21.6 million (the “Target Amount”).  In the initial phase of the settlement, CEPM transferred 484,505 Class A units of CEP, representing 100% of the Class A units it owned, to SEPI, and received the sum of $817,767 from SEPI and an initial payment in the sum of $6,516,103 from CEP.  The $6.5 million was recorded as a valuation allowance related to the CEP investment in accordance with the principles of cost recovery. When the value of the Company’s net investment reaches zero, the Company will start realizing gains/losses in net income.  In addition, CEPM transferred 414,938 CEP Class B units to SEPI in exchange for $1 million from SEPI. After the Company’s mark to market adjustment for the B units, a loss of $78,839 was recorded in the investment valuation allowance; however, as mentioned earlier, no realized gain/loss will be recorded until the value of our investment reaches zero.  

During the second quarter of 2014, the Company sold 1,221,456 Class B units at a weighted average price of $2.45 per unit.As of July 1, 2014, CEPM owned 4,282,500 Class B units, which it intends to dispose of subject to minimum price, volume and other limitations set forth in the settlement agreement. The Class B units may be sold in open market sales and underwritten offerings permitted by and subject to the terms of the settlement agreement.  In certain circumstances, SEPI may require CEPM to sell up to one-half of the subject units to third parties identified by SEPI.

If, following application of (i) the amounts received in the initial phase as noted above and (ii) proceeds from the sale of all of CEPM’s Class B units, the Target Amount has not been met, SEPI will pay CEPM the difference, up to a maximum of $5 million.  On the other hand, if the Target Amount has been exceeded, CEPM will pay SEPI 50% of the surplus, up to a maximum payment to SEPI of $5 million.

The settlement agreement provides that until CEPM’s ownership of Class B units has been reduced to less than one million units, CEPM has the right to appoint one observer to the CEP board of managers. The settlement agreement also contains certain restrictions concerning CEPM’s voting on issues brought to a unit-holder vote and participating in proxy solicitations or contests.

F-9

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:

	Six Months Ended June 30,
	2013		2014
	(in thousands)
Asset retirement obligations at beginning of period	$	10,868	$	13,228
Liabilities incurred		237		37
Liabilities settled		(1)		(118)
Accretion		387		518
Asset retirement obligations at end of period	$	11,491	$	13,665
Current portion of asset retirement obligations	$	—	$	134
Noncurrent portion of asset retirement obligations	$	11,491	$	13,531

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:

	December 31,		June 30,
	2013		2014
	(in thousands)
Borrowing Base Facility	$	92,000	$	87,000
Less current maturities		—		—
Total long-term debt	$	92,000	$	87,000

The borrowing base under the Borrowing Base Facility was redetermined on May 22, 2014, based on reserves at December 31, 2013, and remained unadjusted at $115 million. With outstanding borrowings of $87.0 million and letters of credit of $1.4 million, $26.6 million was available for additional borrowings at June 30, 2014. The terms of the Borrowing Base Facility are described within Note 10 of Item 8. Financial Statement and Supplementary Data in the 2013 10-K. The Company was in compliance with all of its financial covenants under the Borrowing Base Facility at June 30, 2014.

Note 8 — Redeemable Preferred Stock and Warrants

Effective June 27, 2014, the Company and White Deer agreed to extend from December 31, 2014 to June 30, 2016 the date through which the Company may accrue dividends rather than pay them in cash for all outstanding Series A preferred stock. 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 $2.3 million during the six months ended June 30, 2014.

The following table summarizes changes in the Series A Preferred Stock and associated warrants:

	Carrying Value		Carrying Value		Number of	Liquidation
	of Series A		of Series A		Outstanding	Value of		Number of	Weighted Average
	Preferred Stock in		Preferred Stock		Series A	Series A		Outstanding	Exercise Price of
	Temporary Equity		in Liabilities		Preferred Shares	Preferred Stock		Warrants	Warrants
	(in thousands except share, warrant and per unit data)
December 31, 2013	$	23,828	$	64,523	7,250	$	102,806	20,161,351	$	1.54
Accrued dividends		4,009		—	—		6,261	4,517,822		1.39
Accretion		806		822	—		—	—		—
June 30, 2014	$	28,643	$	65,345	7,250	$	109,067	24,679,173	$	1.51

F-10

POSTROCK ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Note 9 — Equity and Earnings per Share

Share-Based Payments — The Company recorded share based compensation expense of $746,000 and $241,000 for the three months ended June 30, 2013 and 2014, respectively, and $1.5 million and $346,000 for the six months ended June 30, 2013 and 2014, respectively. Total share-based compensation to be recognized on unvested stock awards and options at June 30, 2014, is $1.3 million over a weighted average period of 1.35 years. The following table summarizes option and restricted awards granted during 2014 and their associated valuation assumptions:

		Weighted
	Number of	fair value per		Weighted		Weighted		Weighted
	awards granted	option or share		exercise price		risk free rate		volatility
Options
First quarter 2014 employee awards (1)	15,750	$	0.64	$	1.23	1.2	%	68.4	%
Second quarter 2014 employee awards (1)	785,757	$	0.72	$	1.32	1.3	%	73.2	%
Restricted Stock Awards
First quarter 2014 employee awards (1)	9,500	$	1.23		n/a	n/a		n/a
First quarter 2014 director awards (2)	10,991	$	1.16		n/a	n/a		n/a
Second quarter 2014 employee awards (1)	241,850	$	1.32		n/a	n/a		n/a
Second quarter 2014 director awards (3)	55,714	$	1.49		n/a	n/a		n/a

________

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

(2) Awards vest immediately.

(3) 10,714 awards vest immediately, 45,000 awards vest in one year

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 June 30,		Six Months Ended June 30,
	2013	2014	2013	2014
Denominator for basic earnings per share	24,395,241	31,799,356	23,583,859	31,408,761
Effect of potentially dilutive securities
Unvested share-based awards	60,397	—	—	—
Warrants	53,540	—	—	—
Stock options	—	—	—	—
Denominator for diluted earnings per share	24,509,178	31,799,356	23,583,859	31,408,761
Securities excluded from earnings per share calculation due to antidilutive effect
Unvested share-based awards	—	—	22,489	—
Stock options	2,442,709	2,671,119	2,442,709	2,671,119
Warrants	31,619,112	22,823,237	36,351,189	22,823,237

Common Stock Issuance —The Company has an effective $100 million universal shelf registration statement under which it has sold common shares pursuant to an at-the-market issuance sales agreement with a sales agent. During the six months ended June 30, 2013, the Company sold 2,592,313 common shares for net proceeds of $4.0 million, under the program. No shares were sold during the six months ended June 30, 2014.

The Company issued an additional 725,806 common shares with a fair value of approximately $900,000 as partial payment on a Central Oklahoma property acquisition in January 2014.

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

F-11

POSTROCK ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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 — Investment, the Company has settled the lawsuit against CEP, CEP’s Chief Executive Officer, members of CEP’s Board of Managers, Sanchez Oil & Gas Corporation and SEPI.

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 six months ended June 30, 2014, the Company entered into new contractual commitments for compressors. As a result, the $7.2 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, 2013.

Other than the contractual commitments discussed above and additional debt borrowings during the six months ended June 30, 2014, there were no material changes to the Company’s contractual commitments since December 31, 2013.

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 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 six months ended June 30, 2014,  224,445 shares of common stock were contributed to the 401K plan, of which 224,198 shares were issued by the Company, and 247 shares were funded with forfeited shares already in the plan.

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:

	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2014		2013		2014
	(in thousands)
401(k) profit sharing plan cost	$	164	$	155	$	363	$	304

Deferred compensation plan — Effective January 1, 2013, the Company established a deferred compensation plan that permits members of its board and certain employees 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 for the three months and six months ended June 30, 2013 and 2014. 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.

	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2014		2013		2014
	(in thousands, except per share amounts)
Shares of common stock contributed		260,382		576,552		260,382		1,492,361
Fair value of common stock contributed	$	383	$	801	$	383	$	1,924

F-12

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, and Central Oklahoma. We also have minor oil and gas producing properties in the Appalachian Basin. Our Cherokee Basin and Central Oklahoma properties comprise our MidContinent area of operations.

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, 2013.

2014 Drilling Program and Production Update

Central Oklahoma

Oil production for the first half of the year averaged 403 net barrels per day, a 132% increase over the prior-year period. Capital spending for the six months ended June 30, 2014, totaled $17.5 million, of which $12.4 million related to Central Oklahoma.During the year, we have performed development workovers on twelve wells. The cost of the workovers totaled approximately $3 million and we expect the return to exceed 100%. During the second quarter, we drilled and completed the first planned horizontal well targeting the Hunton formation at a cost of approximately $2.8 million. In July we spent approximately $150,000. Additionally, we spud our second horizontal well in the Hunton formation at the end of the second quarter and spent approximately $1.5 million. Drilling was completed in mid-July at an additional cost of approximately $1.5 million.  Initial results have been positive, as the development workovers have increased production by approximately 170 net barrels of oil per day while the first horizontal well recently peaked at over 600 Bbls of oil per day and has produced 14,000 Bbls since coming on production in late June.    

On January 31, 2014, we purchased additional interests in producing properties we acquired in November 2013. The additional interests were purchased for $1.8 million, consisting of $900,000 cash and 725,806 shares of our common stock. The acquisition included approximately 960 net acres of leasehold mineral interests, including certain producing oil and gas properties and related wells. The additional interest added approximately 20 net barrels of oil per day. Additionally, we have incurred approximately $1.0 million on geological and geophysical costs in 2014.

On June 12, 2014, we entered into a joint venture (“JV”) agreement with Silver Creek Oil and Gas, LLC (“Silver Creek”) covering approximately 17,900 gross unproved acres in Cleveland and Pottawatomie Counties in central Oklahoma. The JV included an acre for acre swap of approximately 3,800 total net acres. After the swap, the ownership split in the development area is 30% PostRock and 70% Silver Creek, with Silver Creek serving as the operator. We also sold approximately 1,150 net acres to Silver Creek for $466,000 in cash.

For the remainder of the year, we expect to spend approximately $14.5 million to drill, or participate in, four to five additional horizontal wells targeting the Hunton and the Woodford shale formations, at least one vertical well targeting multiple zones, and three to four additional development workovers in Central Oklahoma. Two of the Woodford wells will be drilled as a part of the recent joint venture with Silver Creek. Locations have been identified, and drilling operations are expected to begin in the third quarter. As attractive opportunities are identified, additional capital may be directed towards further oil development in the region.

Cherokee Basin

Oil and gas production for the first half of the year averaged 203 net barrels per day and 34.9 net MMcf per day, respectively. On a year-to-date economic equivalency basis of 21:1, production declined 11% from the prior-year period to an average of 39.2 net MMcfe per day. The decline in production was due to the natural decline of our gas wells as we have not undertaken any development projects in the Cherokee Basin over the past two years in favor or focusing our capital on higher-return oil projects in Central Oklahoma. 

One of our most significant projects over the past roughly 18 months has been the reconfiguration of our Cherokee Basin compression system. This project was designed to improve energy efficiency and reduce gathering and operating costs. The project was completed on May 6, 2014 and the inception to date cost is $8.3 million. The project is expected to result in total annual rental savings of $4.6 million and reduce fuel consumption by approximately 1.6 MMcf per day.

1

Three Months Ended June 30, 2013 Compared to the Three Months Ended June 30, 2014

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

	Three Months Ended June 30,				Increase/
	2013		2014		(Decrease)
	($ in thousands except per unit data)
Natural gas sales	$	14,434	$	14,656	$	222	1.5	%
Crude oil sales	$	4,444	$	6,194	$	1,750	39.4	%
Production expense	$	10,702	$	10,564	$	(138)	(1.3)	%
General and administrative	$	4,259	$	3,499	$	(760)	(17.8)	%
Depreciation, depletion and amortization	$	6,693	$	7,357	$	664	9.9	%
Other income (expense)	$	8,899	$	(6,210)	$	(15,109)	*
Sales Data - Volumes
Natural gas sales (MMcf)		3,635		3,336		(299)	(8.2)	%
Oil sales (Bbls)		49,481		62,050		12,569	25.4	%
Total sales (MMcfe)		3,932		3,709		(223)	(5.7)	%
Average daily sales (MMcfe/d)		43.2		40.8		(2.4)	(5.7)	%
Average Sales Price per Unit
Natural gas (Mcf)	$	3.97	$	4.39	$	0.42	10.6	%
Oil (Bbl)	$	89.81	$	99.82	$	10.01	11.1	%
Natural gas equivalent (Mcfe)	$	4.80	$	5.62	$	0.82	17.1	%
Average Unit Costs per Mcfe
Production expense	$	2.72	$	2.85	$	0.13	4.7	%
Depreciation, depletion and amortization	$	1.70	$	1.98	$	0.28	16.7	%

____________

* Not meaningful

Natural gas sales increased $222,000, or 1.5%, from $14.4 million during the three months ended June 30, 2013, to $14.7 million during the three months ended June 30, 2014. Higher natural gas prices resulted in increased revenues of $1.4 million while lower gas volumes partially offset that increase by $1.2 million. The decline in gas volumes resulted from the lack of gas development projects in the last two years as we focus our capital on higher-return oil projects in Central Oklahoma. Our average realized natural gas price increased from $3.97 per Mcf for the three months ended June 30, 2013, to $4.39 per Mcf for the three months ended June 30, 2014.

Oil sales increased $1.8 million, or 39.4%, from $4.4 million during the three months ended June 30, 2013, to $6.2 million during the three months ended June 30, 2014. Higher oil volumes resulted in increased revenues of $1.1 million while higher oil prices increased revenue by an additional $621,000. 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 $89.81 per barrel for the three months ended June 30, 2013, to $99.82 per barrel for the three months ended June 30, 2014.

Production expense, consisting of lease operating expenses, severance and ad valorem taxes (“production taxes”) and gathering expense, decreased by $138,000, or 1.3 %, from $10.7 million during the three months ended June 30, 2013, to $10.6 million during the three months ended June 30, 2014.  Lease operating costs decreased $879,000 in the Cherokee Basin primarily due to compressor cost savings as a result of our compressor optimization project. These decreases were offset by an increase in lease operating and severance taxes in Central Oklahoma of $669,000 and $169,000, respectively, as a result of higher production in the area.  The remainder of the decrease related to lower production taxes in the Cherokee Basin. Production costs were $2.72 per Mcfe for the three months ended June 30, 2013, as compared to $2.85 per Mcfe for the three months ended June 30, 2014.  

Depreciation, depletion and amortization increased $664,000, or 9.9%, from $6.7 million during the three months ended June 30, 2013, to $7.4 million during the three months ended June 30, 2014. On a per unit basis, we had an increase of $0.28 per Mcfe from $1.70 per Mcfe during the three months ended June 30, 2013, to $1.98 per Mcfe during the three months ended June 30, 2014. The increase was primarily a result of an increase in the depreciation rate which was partially offset by lower volumes.

General and administrative expenses decreased $760,000, or 17.8%, from $4.3 million during the three months ended June 30, 2013, to $3.5 million during the three months ended June 30, 2014.  Excluding a $528,000 charge stemming from a 2009 workman’s

2

compensation insurance audit that was expensed in the prior-year period, general and administrative expenses decreased by 6%. The decrease was largely due to decreased non-cash compensation in the current period.

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 loss on our derivative contracts of $1.3 million for the three months ended June 30, 2013, compared to a realized loss of $1.9 million for the three months ended June 30, 2014.  We recorded an unrealized gain from derivative instruments of $10.1 million and unrealized loss of $894,000 for the three months ended June 30, 2013 and 2014, respectively. We recorded a mark-to-market gain of $863,000 and  $87,000 on our investment in CEP for the three months ended June 30, 2013 and 2014, respectively. Interest expense, net, was $769,000 during the three months ended June 30, 2013, and $3.5 million during the three months ended June 30, 2014.  Excluding non-cash interest of $2.6 million related to our Series A Preferred Stock, interest expense, net was $915,000 in the 2014 period.

Six Months Ended June 30, 2013 Compared to the Six Months Ended June 30,2014

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

	Six Months Ended June 30,				Increase/
	2013		2014		(Decrease)
	($ in thousands except per unit data)
Natural gas sales	$	26,876	$	30,619	$	3,743	13.9	%
Crude oil sales	$	7,401	$	11,299	$	3,898	52.7	%
Production expense	$	20,477	$	20,836	$	359	1.8	%
General and administrative	$	7,805	$	7,410	$	(395)	(5.1)	%
Depreciation, depletion and amortization	$	13,121	$	14,259	$	1,138	8.7	%
Other income (expense)	$	4,732	$	(13,236)	$	(17,968)	*
Sales Data - Volumes
Natural gas sales (MMcf)		7,355		6,594		(761)	(10.3)	%
Oil sales (Bbls)		82,160		115,636		33,476	40.7	%
Total sales (MMcfe)		7,848		7,288		(560)	(7.1)	%
Average daily sales (MMcfe/d)		43.4		40.3		(3.1)	(7.2)	%
Average Sales Price per Unit
Natural gas (Mcf)	$	3.65	$	4.64	$	0.99	27.2	%
Oil (Bbl)	$	90.08	$	97.71	$	7.63	8.5	%
Natural gas equivalent (Mcfe)	$	4.37	$	5.75	$	1.38	31.6	%
Average Unit Costs per Mcfe
Production expense	$	2.61	$	2.86	$	0.25	9.5	%
Depreciation, depletion and amortization	$	1.67	$	1.96	$	0.29	17.2	%

____________

* Not meaningful

Natural gas sales increased $3.7 million, or 13.9%, from $26.9 million during the six months ended June 30, 2013, to $30.6 million during the six months ended June 30, 2014. Higher natural gas prices resulted in increased revenues of $6.5 million while lower gas volumes partially offset that increase by $2.8 million. In addition to significant weather-related interruption in the first quarter of 2014, the decline in gas volumes resulted from the lack of gas development projects in the last two years as we focus our capital on higher-return oil projects in Central Oklahoma. Our average realized natural gas price increased from $3.65 per Mcf for the six months ended June 30, 2013, to $4.64 per Mcf for the six months ended June 30, 2014.

Oil sales increased $3.9 million, or 52.7%, from $7.4 million during the six months ended June 30, 2013, to $11.3 million during the six months ended June 30, 2014. Higher oil volumes resulted in increased revenues of $3.0 million while higher oil prices provided an additional increase of $882,000. Our average realized oil price increased from $90.08 per barrel for the six months ended June 30, 2013, to $97.71 per barrel for the six months ended June 30, 2014.

Production expense increased $359,000, or 1.8%, from $20.5 million for the six months ended June 30, 2013, to $20.8 million for the six months ended June 30, 2014. The increase was primarily due to more production activity in Central Oklahoma which increased operating costs and severance taxes by $1.2 million and $269,000, respectively. This increase was offset by decreased operating costs primarily related to compressor cost savings in the Cherokee Basin of $1.0 million. Production costs were $2.61 per Mcfe for the six

3

months ended June 30, 2013, as compared to $2.86 per Mcfe for the six months ended June 30, 2014.

Depreciation, depletion and amortization increased $1.1 million, or 8.7%, from $13.1 million during the six months ended June 30, 2013, to $14.3 million during the six months ended June 30, 2014. On a per unit basis, we had an increase of $0.29 per Mcfe from $1.67 per Mcfe during the six months ended June 30, 2013, to $1.96 per Mcfe during the six months ended June 30, 2014. The increase was primarily a result of an increase in the depreciation rate which was partially offset by lower volumes.

General and administrative expenses decreased $395,000, or 5.1%, from $7.8 million during the six months ended June 30, 2013, to $7.4 million during the six months ended June 30, 2014. The decrease was mainly due to the $528,000 workman’s compensation charge in 2013 as discussed above.  The remaining variance was due to higher legal, license, and board fees partially offset by lower compensation.

Other income (expense) consists primarily of realized and unrealized gains or losses from derivative instruments, gain from investment, and net interest expense. We realized losses on our derivative contracts of $2.2 million for the six months ended June 30, 2013, compared to $4.4 million for the six months ended June 30, 2014. Unrealized gains from derivative instruments of $3.9 million were recognized for the six months ended June 30, 2013 and an unrealized loss of $3.5 million for the six months ended June 30, 2014. We recorded a mark-to-market gain of $4.4 million and $1.7 million on our investment in CEP for the six months ended June 30, 2013 and 2014, respectively.Interest expense, net, was $1.4 million during the six months ended June 30, 2013, and $7.0 million during the six months ended June 30, 2014. Excluding non-cash interest of $5.1 million related to our Series A Preferred Stock, interest expense, net was $1.9 million, higher compared to the prior period as a result of higher debt in the current period.

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 helps 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 six months ended June 30, 2014, were cash from operations, proceeds from our settlement of the CEP lawsuit and the subsequent sale of CEP Class B units. At June 30, 2014, our debt decreased by $5.0 million from December 31, 2013. The decrease was primarily due to repayments under our credit facility, utilizing proceeds from the sale of CEP settlement and subsequent sales of CEP Class B units. 

Cash Flows from Operating Activities

Cash flows provided by operating activities were $1.2 million for the six months ended June 30, 2013, compared to $8.5 million for the six months ended June 30, 2014. The increase in cash was primarily a result of an increase in revenues of $7.8 million from the prior year period as realized commodity prices were higher.

Cash Flows from Investing Activities

Cash flows used in investing activities were $25.1 million for the six months ended June 30, 2013, compared to $3.5 million for the six months ended June 30, 2014. The decreased outflow was primarily due to lower capital expenditures in the current period and by proceeds from the sale of CEP Class B units. Capital expenditures in the prior-year period were higher as a result of a higher number of oil development projects when compared to the number of projects in the current period. Acquisition and development capital expenditures in the current year reflect our expanded oil activity in Central Oklahoma. ‘Other’ capital expenditures are mainly costs associated with our compressor optimization project in the Cherokee Basin. 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, 2014:

	Six Months Ended
	June 30, 2014
	(in thousands)
Capital expenditures
Acquisition	$	3,582
Development		9,137
Other		4,813
Total capital expenditures	$	17,532

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Cash Flows from Financing Activities

Cash flows from financing activities were $23.7 million for the six months ended June 30, 2013, as compared to cash flows used of $5.0 million for the six months ended June 30, 2014. The difference in cash flows was primarily driven by debt borrowing in the prior year compared to repayments in the current year. Debt borrowings were $20.0 million for the six months ended June 30, 2013, compared to repayments of $5.0 million for the six months ended June 30, 2014. The repayments in the current year were facilitated by proceeds from the sale of our CEP Class B units. Also, during the six months ended June 30, 2013, we had proceeds from the issuance of common stock of $4.1 million.

Sources of Liquidity in 2014 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. In the first quarter of 2014, we settled our lawsuit with CEP and SEPI and used proceeds received to reduce bank debt.  The settlement positions us to redeploy capital into oil-focused development projects primarily in Central Oklahoma. As of July 31, 2014, we had sold an additional 1,116,984 CEP Class B units at an average price of $2.70 and we continued to own 3,165,516 Class B units which we intend to dispose of over the next six to nine months.

At June 30, 2014, we had a $200 million secured borrowing base revolving credit facility, which we use as an external source of long and short term liquidity. The borrowing base was redetermined on May 22, 2014 based on reserves at December 31, 2013 and remained unchanged at $115 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. With outstanding borrowings of $87.0 million and letters of credit of $1.4 million, $26.6 million was available for additional borrowings at June 30, 2014. The terms of the Borrowing Base 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, 2013. With the current availability under our borrowing base facility, expected cash flows from operations and expected proceeds from further sales of CEP Class B units, we believe that we have sufficient liquidity to fund our capital expenditures and financial obligations for the next 12 months.

Dilution

At June 30, 2014, including 10,958,601 shares of our common stock held by White Deer, we had 30,777,181 shares of common stock outstanding. In addition, we had 24,903,781 outstanding warrants to purchase our common stock of which 24,679,173 are owned by White Deer at an average exercise price of $1.51 and 224,608 are owned by Constellation Energy Group Inc. at an average exercise price of $7.57.  The warrants held by Constellation Energy Group expire on August 8, 2014. We also had 162,451 restricted stock units and 2,671,119 options outstanding granted under our long-term incentive plan. Consequently, if these securities were included as outstanding, our outstanding shares would have been 58,352,081 of which the warrants and common stock owned by White Deer would represent approximately 61%. By exercising its warrants, White Deer can benefit from its 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 it may sell significant amounts of our common stock, the market price of our common stock may be significantly impacted.

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 can be sold. There were no sales of common stock in the first half of the year.

Contractual Obligations

We have numerous contractual commitments in the ordinary course of business including debt service requirements, operating leases and purchase obligations. During the six months ended June 30, 2014, we entered into new contractual commitments for compressors. As a result, the $7.2 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, 2013.

Other than the contractual commitments discussed above and debt repayments during the six months ended June 30, 2014, there were no material changes to the our contractual commitments since December 31, 2013.

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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, 2013, which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements.

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

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 June 30, 2014.

	Remainder of		Year Ending December 31,
	2014		2015		2016		Total
	($ in thousands, except per unit data)
Natural Gas Swaps
Contract volumes (MMBtu)		5,163,786		8,983,560		7,814,028		21,961,374
Weighted-average fixed price per MMBtu	$	4.01	$	4.01	$	4.01	$	4.01
Fair value, net	$	(2,285)	$	(1,818)	$	(1,623)	$	(5,726)
Crude Oil Swaps
Contract volumes (Bbl)		58,038		71,568		65,568		195,174
Weighted-average fixed price per Bbl	$	95.19	$	92.73	$	90.33	$	92.65

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Fair value, net	$	(458)	$	(279)	$	(66)	$	(803)
Total fair value, net	$	(2,743)	$	(2,097)	$	(1,689)	$	(6,529)

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 (who currently serves as our principal financial officer), conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures as of June 30, 2014. Based on that evaluation, our principal executive officer (who also currently serves as our principal financial officer) concluded that, as of June 30, 2014, 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 2013 10-K.

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

The following table provides information regarding purchases of our common stock that were made by us during the first six months of 2014. PostRock does not have any publicly announced equity securities repurchase plans or programs.

	Total Number	Average
	of Shares	Price Paid
	Purchased (1)	per Share
January 1 - January 31	—	$	—
February 1 - February 28	83,363	$	1.25
March 1 - March 31	—	$	—
April 1 - April 30	10,689	$	1.31
May 1 - May 31	402	$	1.38
June 1 - June 30	601	$	1.43
Total	95,055	$	1.26

_________

(1) Share repurchases represent shares withheld by us from employees for the payment of personal income tax withholding on restricted stock vesting.  7  

ITEM 6. EXHIBITS

31.1*	Certification by principal executive officer who also serves as 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 who also serves as 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.

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 not 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 7th day of August 2014.

PostRock Energy Corporation
By:	/s/ Terry W. Carter
	Terry W. Carter
	Chief Executive Officer and President

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