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PSTR > SEC Filings for PSTR > Form 10-Q on 6-Nov-2013All Recent SEC Filings

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Form 10-Q for POSTROCK ENERGY CORP


6-Nov-2013

Quarterly Report


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. We also have oil producing properties in Oklahoma and minor oil and gas producing properties in the Appalachian Basin. We previously owned an interstate natural gas pipeline which was sold in September 2012 and we report its results as a discontinued operation in our financial statements. Unless the context requires otherwise, references to "PostRock," the "Company," "we," "us" and "our" refer to PostRock Energy Corporation and its consolidated subsidiaries.

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

2013 Drilling Program and Production Update

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

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

Central Oklahoma Property Acquisition

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

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


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

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

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


____________

* Not meaningful

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

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

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

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

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


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

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

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

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

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

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


____________

* Not meaningful

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


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

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

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

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

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

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

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

Liquidity and Capital Resources

Cash flows from operating activities have historically been driven by the quantities of our production and the prices received from the sale of our production. Prices of oil and gas have historically been very volatile and can significantly impact the cash received from the sale of our production. Use of derivative financial instruments help mitigate this price volatility. Proceeds from or payments for derivative settlements are included in cash flows from operations. Cash expenses also impact our operating cash flow and consist primarily of production expenses, interest on our indebtedness and general and administrative expenses.

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


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Cash Flows from Operating Activities

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

Cash Flows from Investing Activities

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

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

Cash Flows from Financing Activities

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

Sources of Liquidity in 2013 and Capital Requirements

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


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

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

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

Dilution

At September 30, 2013, including 9,834,620 shares of our common stock held by White Deer, we had 24,636,051 shares of common stock outstanding. In addition, we had 40,170,845 outstanding warrants to purchase our common stock of which 39,946,237 are owned by White Deer at an average exercise price of $2.50 and 224,608 are owned by Constellation Energy Group Inc. at an average exercise price of $7.57. We also had 192,351 restricted stock units and 2,323,159 options outstanding granted under our long-term incentive plan. Consequently, if these securities were included as outstanding, our outstanding shares would have been 67,322,406 of which the warrants and common stock owned by White Deer would represent approximately 74 %. By exercising their warrants, White Deer can benefit from their respective percentage of all of our profits and growth. In addition, if White Deer begins to sell significant amounts of our common stock, or if public markets perceive that they may sell significant amounts of our common stock, the market price of our common stock may be significantly impacted.

Contractual Obligations

We have numerous contractual commitments in the ordinary course of business including debt service requirements, operating leases and purchase obligations. During the nine months ended September 30, 2013, we entered into new contractual commitments for software, information technology equipment and services, compressors and office space. We also entered into a sublease of unutilized office space at our corporate headquarters allowing us to reduce future rent expense for that facility. As a result, the $5.8 million minimum amount of these contracts over a span of five years would be an increase to the amount included in our outstanding contractual commitments table at December 31, 2012.

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

Forward-Looking Statements

Various statements in this report, including those that express a belief, expectation, or intention, as well as those that are not statements of historical fact, are forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These statements include those . . .

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