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, 2014

 

Commission file number: 001-34635

______________________

 

POSTROCK ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

______________________

 

 

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):

 

 

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

 

At October 31, 2014, there were 63,138,283 outstanding shares of the registrant’s common stock having an aggregate market value of $45.5 million based on a closing price of $0.72 per share.

 

 

 

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POSTROCK ENERGY CORPORATION

FORM 10-Q

FOR THE QUARTER ENDED SEPTEMBER 30, 2014

 

TABLE OF CONTENTS

 

 

 

 

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PART I — FINANCIAL INFORMATION

 

Item 1. Financial Statements

 

POSTROCK ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands, except share and per share data)

 

 

The accompanying notes are an integral part of these statements.

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POSTROCK ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

 

 

The accompanying notes are an integral part of these statements.

 

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POSTROCK ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

 

The accompanying notes are an integral part of these statements.

 

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POSTROCK ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF STOCKHOLDERS’ DEFICIT

(Amounts subsequent to December 31, 2013 are unaudited)

 

 

 

The accompanying notes are an integral part of these statements.

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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:

 

 

 

 

 

 

 

 

 

 

 

 

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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 September 30, 2014, the Company was a net obligor with respect to outstanding derivative contracts with one 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:

 

 

 

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

 

 

 

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.

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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.

 

 

 

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, 2014.

 

 

 

 

 

 

 

 

 

 

 

 

 

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.

 

 

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Investment — The Company has an investment in Constellation Energy Partners LLC, now named Sanchez Production Partners LLC (“CEP”), which consisted of 1,598,795 Class B units at September 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 September 30, 2014, the fair value used for the Class B units was $3.56 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. Since 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:

 

 

 

There were no movements between Levels 1 and 2 during the nine months ended September 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 September 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 September 30, 2014 were $40.5 million and $31.3 million, respectively, for the portion reflected as temporary equity and $71.9 million and $65.8 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 7.8% at December 31, 2013 and September 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.

 

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

 

 

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):

 

 

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. In the first quarter after the Company’s mark to market adjustment for the B units, a loss of $78,839 was recorded in the investment valuation allowance.

 

During the third quarter of 2014, the Company sold 2,683,705 Class B units at a weighted average price of $2.95 per unit. The value of the Company’s investment in CEP has reached zero; therefore, we recorded a realized gain of approximately $667,000. As of September 30, 2014, CEPM owned 1,598,795 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. As of September 30, 2014, CEPM had recovered approximately $19.2 million of the Target Amount.

 

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.

 

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Note 6 — Asset Retirement Obligations 

 

The following table reflects the changes to asset retirement obligations for the periods indicated:

 

 

 

 

 

 

 

 

 

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:

 

 

The borrowing base under the Borrowing Base Facility was redetermined on October  31, 2014, based on reserves at June 30, 2014, and remained unadjusted at $115 million. With outstanding borrowings of $80.0 million and letters of credit of $1.4 million, $33.6 million was available for additional borrowings at September 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 September 30, 2014.

 

Note 8 — Redeemable Preferred Stock and Warrants 

 

Prior to June 30, 2016, 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 $3.3 million during the nine months ended September 30, 2014.  The following table summarizes changes in the Series A Preferred Stock and associated warrants:

 

 

 

 

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Subsequent Event

 

On October 9, 2014, PostRock and White Deer Energy L.P. and its affiliates (collectively, “White Deer”) entered into a Preferred Stock Exchange Agreement, pursuant to which PostRock issued 32,113,782 shares of its common stock to White Deer in exchange for 2,175 shares of Series A Preferred Stock issued to White Deer on September 21, 2010.  The Series A Preferred Stock had an aggregate liquidation preference of $35.0 million, as calculated pursuant to the certificate of designations for the Series A Preferred Stock.  On March 21, 2018, all then-outstanding Series A Preferred Stock must be redeemed for 100% of the liquidation preference. 

 

The shares of common stock issued in the exchange were valued at an exchange price of $1.09 per share, which is the average Nasdaq closing price for the common stock for the ten trading days immediately preceding the execution of the exchange agreement.  Following the exchange, White Deer owns 43,072,383 shares of common stock, 5,075 shares of Series A Preferred Stock and warrants to purchase 27,448,492 shares of common stock. 

 

 

Note 9 — Equity and Earnings per Share 

 

Share-Based Payments — The Company recorded share based compensation expense of $618,000 and $264,000 for the three months ended September 30, 2013 and 2014, respectively, and $2.1 million and $609,000 for the nine months ended September 30, 2013 and 2014, respectively. Total share-based compensation to be recognized on unvested stock awards and options at September 30, 2014, is $1.1 million over a weighted average period of 1.33 years. The following table summarizes option and restricted awards granted during 2014 and their associated valuation assumptions:

 

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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:

 

 

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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 nine months ended September 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 nine months ended September 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 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 nine months ended September 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 nine months ended September 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 nine months ended September 30, 2014, 340,553 shares of common stock were contributed to the 401K plan, of which 337,631 shares were issued by the Company, and 2,922 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:

 

 

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.

 

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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 nine months ended September 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.

 

 

 

 

 

 

 

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

 

Capital spending for the nine months ended September 30, 2014, totaled $24.5 million, of which $18.1 million related to Central Oklahoma. We expect total capital expenditures for the year to be approximately $33.0 million as we complete development and maintenance projects underway or planned for the balance of the year.

 

Central Oklahoma

 

Oil production for the first nine months of the year averaged 502 net barrels per day, a 164% increase over the prior-year period. During the year, we have performed development workovers on thirteen wells. The cost of the workovers totaled approximately $3 million and we expect the return to exceed 100%. The development workovers increased production by approximately 105 net barrels of oil per day. During the second and third quarters, we drilled and completed two horizontal wells targeting the Hunton formation at a cost of approximately $6.0 million. The first horizontal well peaked in July at over 600 gross barrels of oil per day. It has produced 41,000 gross barrels of oil since coming on production in late June. The second well reached peak production of 230 gross barrels of oil per day. Despite a less than satisfactory start, the well has produced just over 11,000 gross barrels of oil since being put on production in July and is currently producing 80 gross barrels of oil per day. In September we spud the third horizontal oil well of 2014 targeting the Hunton formation. It is expected to be on-line in early November. The fourth 2014 horizontal well targeting the Hunton is currently being drilled and is expected to be completed and on-line in December. Total cost for the two horizontal wells is expected to be $6.5 million as the average lateral length is 700 feet longer than the recent wells. Additionally, a vertical well targeting the Viola and Red Fork formations in Pottawatomie County, Oklahoma was drilled, then completed subsequent to the quarter, at a cost of approximately $650,000. The vertical well was placed on production in late October to test the Viola; a completion in the Red Fork will likely be added.

 

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 in 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. In the third quarter, Silver Creek began drilling two horizontal wells which are currently being completed. Through the end of September we have spent approximately $1.4 million on the JV wells. Both wells were put on production in October and are currently flowing back frac load along with small amounts of oil. Definitive results are not likely to be obtained until after year-end. PostRock retains its interest and potential operatorship of its remaining 17,500 acres in the area, but outside the JV. Besides the Woodford, the acreage has additional target horizons including the Viola, Hunton, and various Pennsylvanian sands.

 

Cherokee Basin

 

Oil and gas production for the first nine months of the year averaged 191 net barrels per day and 34.8 net MMcf per day, 29% and 10%, respectively, below the prior year period.  The sharp decline in oil production was due to the lack of additional development since August 2013 as oil development results last year were unfavorable. The gas decline was an improvement from the 11 to 13% historic decline due to compression fuel savings in combination with improved operating performance. Over the last five months, gas decline has moderated further to about an 8% annual decline rate as a result of operational improvements and small workovers.

 

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One of our most significant projects over the past 21 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 at cost of approximately  $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.

 

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

 

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

 

 

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* Not meaningful

 

Natural gas sales increased $424,000, or 3.4%, from $12.4 million during the three months ended September 30, 2013, to $12.9 million during the three months ended September 30, 2014. Higher natural gas prices resulted in increased revenues of $1.5 million while lower gas volumes partially offset that increase by $1.1 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 $3.41 per Mcf for the three months ended September 30, 2013, to $3.86 per Mcf for the three months ended September 30, 2014.

 

Oil sales increased $2.3 million, or 40.8%, from $5.6 million during the three months ended September 30, 2013, to $7.8 million during the three months ended September 30, 2014. Higher oil volumes resulted in increased revenues of $2.9 million while lower oil prices partially offset that increase by $594,000. 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 decreased from $101.99 per barrel for the three months ended September 30, 2013, to $94.79 per barrel for the three months ended September 30, 2014.

 

Production expense, consisting of lease operating expenses, severance and ad valorem taxes (“production taxes”) and gathering expense, increased by $826,000, or 8.3%, from $10.0 million during the three months ended September 30, 2013, to $10.8 million during the three months ended September 30, 2014.  Ad valorem taxes increased $334,000 while lease operating costs and severance taxes in Central Oklahoma increased $1.0 million and $97,000, respectively, as a result of higher production in the area. These increases were offset by a decrease in lease operating costs of $599,000 in the Cherokee Basin, primarily due to compressor cost savings as a result of our compressor optimization project, while the remainder of the decrease related to lower operating costs in Appalachia. Production costs were $15.10 per Boe for the three months ended September 30, 2013, as compared to $16.97 per Boe for the three months ended September 30, 2014.  

 

 

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Depreciation, depletion and amortization increased $300,000, or 4.3%, from $7.0 million during the three months ended September 30, 2013, to $7.3 million during the three months ended September 30, 2014. On a per unit basis, we had an increase of $0.87 per Boe from $10.52 per Boe during the three months ended September 30, 2013, to $11.40 per Boe during the three months ended September 30, 2014. The increase was primarily a result of an increase in the deprecation rate which was partially offset by lower volumes.

 

General and administrative expenses decreased $255,000, or 7.4%, from $3.5 million during the three months ended September 30, 2013, to $3.2 million during the three months ended September 30, 2014.  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 $145,000 for the three months ended September 30, 2013, compared to $179,000 for the three months ended September 30, 2014. We recorded an unrealized gain from derivative instruments of $1.3 million and $6.6 million for the three months ended September 30, 2013 and 2014, respectively. We recorded a realized gain on our investment in CEP of $667,000 for the three months ended September 30, 2014. We recorded a mark-to-market gain of $740,000 and $2.3 million on our investment in CEP for the three months ended September 30, 2013 and 2014, respectively. Interest expense, net, was $883,000 during the three months ended September 30, 2013, and $3.4 million during the three months ended September 30, 2014. Excluding non-cash interest of $2.6 million related to our Series A Preferred Stock, interest expense, net was $867,000 in the 2014 period.

 

Nine Months Ended September 30, 2013 Compared to the Nine Months Ended September 30, 2014

 

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

 

 

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* Not meaningful

 

Natural gas sales increased $4.2 million, or 10.6%, from $39.3 million during the nine months ended September 30, 2013, to $43.5 million during the nine months ended September 30, 2014. Higher natural gas prices resulted in increased revenues of $8.0 million while lower gas volumes partially offset that increase by $3.8 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 $3.57 per Mcf for the nine months ended September 30, 2013, to $4.38 per Mcf for the nine months ended September 30, 2014.

 

Oil sales increased $6.2 million, or 47.6%, from $13.0 million during the nine months ended September 30, 2013, to $19.1 million during the nine months ended September 30, 2014. Higher oil volumes resulted in increased revenues of $5.8 million while higher oil

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prices provided an additional increase of $331,000. Our average realized oil price increased from $94.83 per barrel for the nine months ended September 30, 2013, to $96.49 per barrel for the nine months ended September 30, 2014.

 

Production expense increased $1.2 million, or 3.9%, from $30.5 million for the nine months ended September 30, 2013, to $31.6 million for the nine months ended September 30, 2014. The increase was primarily due to more production activity in Central Oklahoma which increased operating costs and severance taxes by $2.2 million and $366,000, respectively. This increase was offset by decreased operating costs primarily related to compressor cost savings in the Cherokee Basin of $1.6 million. The remaining variance was primarily due to higher ad valorem taxes. Production costs were $15.47 per Boe for the nine months ended September 30, 2013, as compared to $17.09 per Boe for the nine months ended September 30, 2014.

 

Depreciation, depletion and amortization increased $1.4 million, or 7.2%, from $20.1 million during the nine months ended September 30, 2013, to $21.5 million during the nine months ended September 30, 2014. On a per unit basis, we had an increase of $1.42 per Boe from $10.20 per Boe during the nine months ended September 30, 2013, to $11.62 per Boe during the nine months ended September 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 $650,000, or 5.8%, from $11.3 million during the nine months ended September 30, 2013, to $10.6 million during the nine months ended September 30, 2014.  Excluding a $528,000 charge stemming from a 2009 workman’s compensation insurance audit that was expensed in the prior year period, general and administrative expenses decreased 1.1%. The decrease was largely due to decreased non-cash compensation in the current year.

 

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 $2.3 million for the nine months ended September 30, 2013, compared to $4.6 million for the nine months ended September 30, 2014. Unrealized gains from derivative instruments of $5.2 million and $3.1 million were recognized for the nine months ended September 30, 2013 and 2014, respectively. We recorded a realized gain on our investment in CEP of $667,000 in the 2014 period. We also recorded a mark-to-market gain of $5.2 million and $4.0 million on our investment in CEP for the nine months ended September 30, 2013 and 2014, respectively. Interest expense, net, was $2.3 million during the nine months ended September 30, 2013, and $10.5 million during the nine months ended September 30, 2014. Excluding non-cash interest of $7.7 million related to our Series A Preferred Stock, interest expense, net was approximately $2.7 million in the 2014 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 nine months ended September 30, 2014, were cash from operations, proceeds from our settlement of the CEP lawsuit and the subsequent sale of CEP Class B units. At September 30, 2014, our debt decreased by $12.0 million from December 31, 2013. The decrease was primarily due to repayments under our credit facility, utilizing proceeds from the CEP settlement and subsequent sales of CEP Class B units.

 

Cash Flows from Operating Activities

 

Cash flows provided by operating activities were $8.9 million for the nine months ended September 30, 2013, compared to $14.2 million for the nine months ended September 30, 2014. The increase in cash was primarily a result of an increase in revenues of $10.4 million from the prior year period as realized commodity prices were higher.

 

Cash Flows from Investing Activities

 

Cash flows used in investing activities were $41.7 million for the nine months ended September 30, 2013, compared to $2.2 million for the nine months ended September 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,

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including costs we have incurred but not paid, by major categories for the nine months ended September 30, 2014:

 

Cash Flows from Financing Activities

 

Cash flows from financing activities were $32.6 million for the nine months ended September 30, 2013, as compared to cash flows used of $12.0 million for the nine months ended September 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 $29.0 million for the nine months ended September 30, 2013, compared to repayments of $12.0 million for the nine months ended September 30, 2014. The repayments in the current year were facilitated by proceeds from the sale of our CEP Class B units. Also, during the nine months ended September 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. Since, the initial settlement, we had sold an additional 3,905,161 CEP Class B units at an average price of $2.80 through September 30, 2014 and we continued to own 1,598,795 Class B units, which we intend to dispose of over the next three to six months. We also may sell non-core assets from time to time to raise additional capital.

 

At September 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 October  31, 2014 based on reserves at June 30, 2014 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 $80.0 million and letters of credit of $1.4 million, $33.6 million was available for additional borrowings at September 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

 

On October 9, 2014, PostRock and White Deer Energy L.P. and its affiliates (collectively, “White Deer”) entered into a Preferred Stock Exchange Agreement, pursuant to which PostRock issued 32,113,782 shares of its common stock to White Deer in exchange for 2,175 shares of Series A Preferred Stock issued to White Deer on September 21, 2010.  The Series A Preferred Stock had an aggregate liquidation preference of $35.0 million, as calculated pursuant to the certificate of designations for the Series A Preferred Stock.  On March 21, 2018, all then-outstanding Series A Preferred Stock must be redeemed for 100% of the liquidation preference. The shares of common stock issued in the exchange were valued at an exchange price of $1.09 per share, which is the average Nasdaq closing price for the common stock for the ten trading days immediately preceding the execution of the exchange agreement.  

 

At October 31, 2014, including 43,072,383 shares of our common stock held by White Deer, we had 63,138,283 shares of common stock outstanding. In addition, we had 27,448,492 outstanding warrants to purchase our common stock, all of which are owned by White Deer, at an average exercise price of $1.48. We also had 1,707,144 shares held in a rabbi trust for our deferred compensation plan, 162,451 restricted stock units and 2,637,057 options outstanding granted under our long-term incentive plan. Consequently, if these securities were included as outstanding, our outstanding shares would have been 95,058,078 of which the warrants and common stock owned by White Deer would represent approximately 74%. 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

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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 nine months 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 nine months ended September 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 nine months ended September 30, 2014, there were no material changes to the our contractual commitments since December 31, 2013.

 

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.

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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, 2014.

 

 

 

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 September 30, 2014. Based on that evaluation, our principal executive officer (who also currently serves as our principal financial officer) concluded that, as of September 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.

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ITEM 6. EXHIBITS 

 

 

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*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 6th day of November 2014.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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