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PSTR > SEC Filings for PSTR > Form 10-Q on 14-Aug-2013All Recent SEC Filings

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Form 10-Q for POSTROCK ENERGY CORP


14-Aug-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 half of 2013, we drilled 113 new oil wells and recompleted 59 wells in the Cherokee Basin and recompleted five wells in Central Oklahoma. Capital spending during the six months ended June 30, 2013, totaled $28.4 million. Of this amount, $20.8 million was spent on oil directed drilling, recompletions and related infrastructure while $3.4 million was spent on maintenance related projects, including compressor optimization projects and truck replacement. An additional $4.2 million was spent on increasing Central Oklahoma acreage from 1,435 net acres at the beginning of the year to 10,440 net acres at quarter end, as well as to extend leases in the Cherokee Basin. As a result of our oil-focused development, net oil sales averaged 454 barrels a day during the first half of 2013 and increased to an average of 544 barrels a day in the second quarter, a 105% increase over the prior-year quarter. Increased revenues from oil along with a modest improvement in natural gas prices have enabled us to grow revenues by 76.1% compared to the prior year quarter. Oil development within the Cherokee Basin is expected to range from 25 to 50 additional new oil wells during the remainder of 2013 as our focus shifts to developing our Central Oklahoma acreage. By quarter's end, we began our drilling program in Central Oklahoma which includes two vertical wells targeting multiple pays, including the Hunton and Woodford formations, as well as a Hunton horizontal well. The Company may drill or participate in one additional vertical well and three to four additional horizontal wells targeting the Woodford, Mississippian and/or Hunton formations in Central Oklahoma by year-end. Our capital spending for the remainder of 2013 is subject to available capital as discussed below in "Sources of Liquidity in 2013 and Capital Requirements."

Gas prices continued to rise going into the second quarter and reached a high of $4.40 per Mmbtu. However, since peaking in late April, gas prices have steadily declined and have slipped back below $4.00 per MMbtu. We will continue to focus on transitioning to a more balanced production profile as expected returns on oil projects continue to exceed those of gas projects. This transition is a significant contributing factor to our 13% decline in gas and 92% increase in oil sales volumes when comparing the six month periods ended June 30, 2012 and 2013.


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

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

                                              Three Months Ended
                                                   June 30,                Increase/
                                               2012         2013          (Decrease)
                                               ($ in thousands except per unit data)
Natural gas sales                            $   8,476    $ 14,434    $  5,958     70.3%
Crude oil sales                              $   2,174    $  4,444    $  2,270    104.4%
Gathering revenue                            $     474    $    716    $    242     51.1%
Production expense                           $  10,699    $ 10,702    $      3      0.0%
Depreciation, depletion and amortization     $   6,940    $  6,693    $   (247)    (3.6%)
Gain (loss) on disposal of assets            $    (266)   $     41    $    307    *
Sales Data
Oil sales (Bbls)                                24,113      49,481      25,368    105.2%
Natural gas sales (Mmcf)                         4,111       3,635        (476)   (11.6%)
Total sales (Mmcfe)                              4,256       3,932        (324)    (7.6%)
Average daily sales (Mmcfe/d)                     46.8        43.2        (3.6)    (7.6%)
Average Sales Price per Unit
Natural Gas (Mcf)                            $    2.06    $   3.97    $   1.91     92.7%
Oil(Bbl)                                     $   90.16    $  89.81    $  (0.35)    (0.4%)
Natural Gas Equivalent (Mcfe)                $    2.50    $   4.80    $   2.30     92.0%
Average Unit Costs per Mcfe
Production expense                           $    2.51    $   2.72    $   0.21      8.4%
Depreciation, depletion and amortization     $    1.63    $   1.70    $   0.07      4.3%


____________

* Not meaningful

Natural gas sales increased $6.0 million, or 70.3 %, from $8.5 million during the three months ended June 30, 2012, to $14.4 million during the three months ended June 30, 2013. Higher natural gas prices resulted in increased revenues of $7.0 million while lower gas volumes partially offset that increase by $1.0 million. The decline in gas volumes resulted from the absence of gas development projects in the last 21 months as gas prices continue to be at uneconomic levels. Our average realized natural gas price increased from $2.06 per Mcf for the three months ended June 30, 2012, to $3.97 per Mcf for the three months ended June 30, 2013.

Oil revenue increased $2.3 million, or 104.4 %, from $2.2 million during the three months ended June 30, 2012, to $4.4 million during the three months ended June 30, 2013. Higher oil volumes resulted in increased revenues of $2.3 million while lower oil prices slightly offset that increase. Our average realized oil price decreased from $90.16 per barrel for the three months ended June 30, 2012, to $89.81 per barrel for the three months ended June 30, 2013.

Gathering revenue increased $242,000, or 51.1 %, from $474,000 for the three months ended June 30, 2012, to $716,000 for the three months ended June 30, 2013. The increase was primarily due to higher realized prices but partially offset by a decrease in gas volumes being transported.

Production expense consists of lease operating expenses, severance and ad valorem taxes ("production taxes") and gathering expense. Production expense was flat across both periods at $10.7 million for the three months ended June 30, 2012 and 2013. Reductions of $367,000 in operating and gathering costs were offset by increased production taxes resulting from improved pricing. As a result of lower volumes, production expense increased from $2.51 per Mcfe for the three months ended June 30, 2012, to $2.72 per Mcfe for the three months ended June 30, 2013.

Depreciation, depletion and amortization decreased $247,000, or 3.6 %, from $6.9 million during the three months ended June 30, 2012, to $6.7 million during the three months ended June 30, 2013. On a per unit basis, we had an increase of $0.07 per Mcfe from $1.63 per Mcfe during the three months ended June 30, 2012, to $1.70 per Mcfe during the three months ended June 30, 2013. The decrease was primarily the result of lower volumes produced and lower depreciation on equipment partially offset by an increase in the depreciation rate.


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General and administrative expenses increased $688,000, or 19.3 %, from $3.6 million during the three months ended June 30, 2012, to $4.3 million during the three months ended June 30, 2013. The increase was primarily due a charge of $528,000 in the current period that resulted from a 2009 workman's compensation insurance audit.

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 $18.6 million for the three months ended June 30, 2012, compared to a realized loss of $1.3 million for the three months ended June 30, 2013. The current quarter loss was primarily due to realized losses on our Southern Star Basis swaps, and to a lesser extent, due to losses on our NYMEX natural gas swaps. These current quarter losses were partially offset by realized gains on our NYMEX oil swaps. In the fourth quarter of 2012, we monetized all of our NYMEX gas swaps scheduled for 2013, which prior to being monetized would have significantly offset the losses realized on the Southern Star Basis swaps. Our natural gas swaps that settled during 2012, including the 2013 swaps that we early-settled during the fourth quarter of 2012, were priced at an average of slightly above $7.00 per Mmbtu. Our 2013 contracts are now priced at an average of approximately $4.01 per Mmbtu. As a result of lower contract prices as well as the expected improvement in natural gas spot prices in 2013, we expect realized gains on our natural gas commodity derivatives to be lower during the remainder of 2013 compared to 2012. We recorded an unrealized loss from derivative instruments of $18.8 million and an unrealized gain of $10.1 million for the three months ended June 30, 2012 and 2013, respectively. We recorded a mark-to-market loss of $6.6 million and a mark-to-market gain of $863,000 on our equity investment in Constellation Energy Partners LLC ("CEP") for the three months ended June 30, 2012 and 2013, respectively. The current quarter gain was the result of an improvement in the market price of CEP's traded units. Gain on forgiveness of debt was $255,000 for the three months ended June 30, 2012. The gain was a result of the settlement of a previous credit facility under a troubled debt restructuring. Interest expense, net, was $2.5 million during the three months ended June 30, 2012, and $769,000 during the three months ended June 30, 2013. Interest was lower as a result of reduced debt.

Six Months Ended June 30, 2012 Compared to the Six Months Ended June 30, 2013

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

                                               Six Months Ended
                                                   June 30,                Increase/
                                              2012          2013          (Decrease)
                                               ($ in thousands except per unit data)
Natural gas sales                           $  20,250     $ 26,876    $  6,626     32.7%
Crude oil sales                             $   4,022     $  7,401    $  3,379     84.0%
Gathering revenue                           $   1,173     $  1,370    $    197     16.8%
Production expense                          $  22,200     $ 20,477    $ (1,723)    (7.8%)
Depreciation, depletion and amortization    $  13,102     $ 13,121    $     19      0.1%
Gain (loss) on disposal of assets           $    (162)    $     10    $    172    *
Sales Data
Oil sales (Bbls)                               42,737       82,160      39,423     92.2%
Natural gas sales (Mmcf)                        8,429        7,355      (1,074)   (12.7%)
Total sales (Mmcfe)                             8,686        7,848        (838)    (9.6%)
Average daily sales (Mmcfe/d)                    47.7         43.4        (4.3)    (9.0%)
Average Sales Price per Unit
Natural Gas (Mcf)                           $    2.40     $   3.65    $   1.25     52.1%
Oil(Bbl)                                    $   94.11     $  90.08    $  (4.03)    (4.3%)
Natural Gas Equivalent (Mcfe)               $    2.79     $   4.37    $   1.58     56.6%
Average Unit Costs per Mcfe
Production expense                          $    2.56     $   2.61    $   0.05      2.0%
Depreciation, depletion and amortization    $    1.51     $   1.67    $   0.16     10.6%


____________

* Not meaningful

Natural gas sales increased $6.6 million, or 32.7 %, from $20.3 million during the six months ended June 30, 2012, to $26.9 million during the six months ended June 30, 2013. Higher natural gas prices resulted in increased revenues of $9.2 million while lower gas volumes partially offset that increase by $2.6 million. The decline in gas volumes resulted from the absence of gas development projects


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in the last 21 months as gas prices continue to be at uneconomic levels. Our average realized natural gas price increased from $2.40 per Mcf for the six months ended June 30, 2012, to $3.65 per Mcf for the six months ended June 30, 2013.

Oil revenue increased $3.4 million, or 84.0 %, from $4.0 million during the six months ended June 30, 2012, to $7.4 million during the six months ended June 30, 2013. Higher oil volumes resulted in increased revenues of $3.7 million while lower oil prices partially offset that increase by $331,000. Our average realized oil price decreased from $94.11 per barrel for the six months ended June 30, 2012, to $90.08 per barrel for the six months ended June 30, 2013.

Gathering revenue increased $197,000, or 16.8 %, from $1.2 million for the six months ended June 30, 2012, to $1.4 million for the six months ended June 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 7.8 %, from $22.2 million for the six months ended June 30, 2012, to $20.5 million for the six months ended June 30, 2013. The variance is driven by lower repair and maintenance costs of $1.0 million, one-time field restructuring costs of $368,000 recognized in the prior-year period, lower workover costs of $259,000 and higher capitalized lease operating expenses of $373,000 as development activities increased. These decreases were partially offset by higher production taxes of $394,000. Production expense was $2.56 per Mcfe for the six months ended June 30, 2012, as compared to $2.61 per Mcfe for the six months ended June 30, 2013. Excluding the one-time field restructuring costs, production expense for the six months ended June 30, 2012, was $2.51 per Mcfe. The increase in per unit production expense was a result of lower volumes.

Depreciation, depletion and amortization was flat across both periods at $13.1 million for the six months ended June 30, 2012 and 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 $0.16 per Mcfe from $1.51 per Mcfe during the six months ended June 30, 2012, to $1.67 per Mcfe during the six months ended June 30, 2013.

General and administrative expenses remained flat across both periods at $7.8 million for the six months ended June 30, 2012 and 2013. The workman's compensation charge discussed above was offset by lower costs for legal and contract services.

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 $30.7 million for the six months ended June 30, 2012, compared to a realized loss of $2.2 million for the six months ended June 30, 2013. The current period loss was due to realized losses on our Southern Star Basis swaps, and to a lesser extent, due to losses on our NYMEX natural gas swaps. These current period losses were partially offset by realized gains on our NYMEX oil swaps. We recorded an unrealized loss from derivative instruments of $18.8 million and an unrealized gain of $3.9 million for the six months ended June 30, 2012 and 2013, respectively. We recorded a mark-to-market loss of $2.5 million and a mark-to-market gain of $4.4 million on our equity investment in CEP for the six months ended June 30, 2012 and 2013, respectively. Gain on forgiveness of debt was $255,000 for the six months ended June 30, 2012. Interest expense, net, was $5.2 million during the six months ended June 30, 2012, and $1.4 million during the six months ended June 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 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, 2013, were proceeds from issuing common stock and borrowings under our borrowing base credit facility. At June 30, 2013, our debt increased by $20.0 million from December 31, 2012. The increase was primarily due to our drilling program, which we accelerated in the second quarter of 2013. 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.

Cash Flows from Operating Activities

Cash flows provided by operating activities was $26.7 million for the six months ended June 30, 2012, compared to $1.2 million for the six months ended June 30, 2013. The decrease in cash was primarily a result of a decrease in realized gains from commodity derivatives where $30.7 million in realized gains were generated in the prior year period compared to $2.2 million in realized losses in


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the current period. The decrease in cash from our derivatives was partially offset by a $10.2 million increase in revenue.

Cash Flows from Investing Activities

Cash flows used in investing activities were $8.7 million for the six months ended June 30, 2012, compared to $25.1 million for the six months ended June 30, 2013. The increased outflow was primarily due to higher capital expenditures which increased from $9.0 million during the six months ended June 30, 2012, to $26.8 million during the six months ended June 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. During the six months ended June 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 six months ended June 30, 2013 (in thousands):

                             Six Months Ended
                               June 30, 2013
Capital expenditures
Leasehold acquisition         $         4,161
Development                            20,847
Other items                             3,409
Total capital expenditures    $        28,417

Cash Flows from Financing Activities

Cash flows used in financing activities were $18.2 million for the six months ended June 30, 2012, as compared to cash received of $23.6 million for the six months ended June 30, 2013. Debt repayments were $25.6 million for the six months ended June 30, 2012, compared to borrowings of $20.0 million for the six months ended June 30, 2013. During the six months ended June 30, 2012, we issued $7.5 million of common stock to White Deer while $4.1 million of common stock was issued during the six months ended June 30, 2013, 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 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 $53.5 million, $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 the first half of 2013, we generated an additional $4.1 million from common stock sales under our at-the-market sales program and issued $180,000 of common stock to partially fund a leasehold purchase. 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 and for working capital purposes.

At June 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 May 8, 2013, based on reserves at December 31, 2012, to be $95 million, an increase of $5 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. At August 12, 2013, with borrowings of $83.5 million and $1.3 million in outstanding letters of credit, we had $10.2 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 remainder of 2013.


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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 six months ended June 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. In June 2013, we suspended sales of our common stock under the program and the program terminates in late August 2013 unless renewed. With the recent modest increase in our borrowing base under the Borrowing Base Facility, we believe we have sufficient near-term liquidity without resorting to the equity sales.

Dilution

At June 30, 2013, including 9,834,620 shares of our common stock held by White Deer, we had 24,562,583 shares of common stock outstanding. In addition, we had 38,178,724 outstanding warrants to purchase our common stock of which 37,729,509 are owned by White Deer at an average exercise price of $2.57 and 449,215 are owned by Constellation Energy Group Inc. at an average exercise price of $7.32. We also had 192,351 restricted stock units and 2,442,709 options outstanding granted under our long-term incentive plan. Consequently, if these securities were included as outstanding, our outstanding shares would have been 65,406,355 of which the warrants and common stock owned by White Deer would represent approximately 73 %. 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 six months ended June 30, 2013, we entered into new contractual commitments for software, information technology 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 $4.0 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 six months ended June 30, 2013, there were no material changes to the our contractual commitments since December 31, 2012.

Forward-Looking Statements

Various statements in this report, including those that express a belief, expectation, or intention, as well as those that are not statements of historical fact, are forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These statements include those regarding projections and estimates concerning the timing and success of specific projects; financial position; business strategy; budgets; amount, nature and timing of capital expenditures; drilling of wells and construction of pipeline infrastructure; acquisition and development of oil and natural gas properties and related pipeline infrastructure; timing and amount of future production of oil and natural gas; operating costs and other expenses; estimated future net revenues from oil and natural gas reserves and the present value thereof; cash flow and anticipated liquidity; funding of our capital expenditures; ability to meet our debt service obligations; and other plans and objectives for future operations.

When we use the words "believe," "intend," "expect," "may," "will," "should," "anticipate," "could," "estimate," "plan," "predict," "project," or their negatives, or other similar expressions, the statements which include those words are usually forward-looking statements. When we describe strategy that involves risks or uncertainties, we are making forward-looking statements. The factors impacting these risks and uncertainties include, but are not limited to:

current weak economic conditions;

. . .

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