Overview

PostRock Energy Corporation ("PostRock") is an independent oil and gas company engaged in the acquisition, exploration, development, production and gathering of crude oil and natural gas. We manage our business in two segments, production and pipeline. Our production segment is focused in the Cherokee Basin, a 15-county region in southeastern Kansas and northeastern Oklahoma. We also have minor oil producing properties in Oklahoma and gas producing properties in the Appalachian Basin. Our pipeline segment consists of a 1,120 mile interstate natural gas pipeline, which transports natural gas from northern Oklahoma and western Kansas to Wichita and Kansas City.

The following discussion should be read together with the unaudited consolidated financial statements and related notes included elsewhere herein and with our annual report on Form 10-K for the year ended December 31, 2011.

2012 Drilling Program Update

For 2012, we budgeted approximately $12.1 million to drill and complete 34 new gas wells in the Cherokee Basin and five new oil wells in central Oklahoma, and recomplete eight oil wells in central Oklahoma and 36 oil wells in the Appalachian Basin. In addition, we budgeted $9.6 million for land, infrastructure and equipment. During 2012, we recompleted 18 wells to increase oil production. Capital spending in the first quarter of 2012 included $1.6 million on drilling and recompletions, $1.4 million to complete our vehicle and equipment efficiency projects, $913,000 to connect two sections of our gathering system to improve production, $751,000 to complete our consolidation and upgrade of facilities in the Cherokee Basin, $62,000 to extend leases in the Cherokee Basin and $113,000 on our interstate pipeline. Our capital spending for the remainder of 2012 is subject to available capital as discussed below in "Sources of Liquidity in 2012 and Capital Requirements."

The significant reduction in natural gas prices at the end of 2011 has continued into 2012, falling below $2.00 per MMbtu in April 2012, and prices are not expected to return to economic levels for some time. As a result, we have curtailed all capital expenditures related to natural gas and have redirected our remaining budgeted drilling capital to oil development opportunities on existing leasehold. These opportunities include the potential for behind-pipe recompletions, workovers and new drilling locations. While we are still in the early stages of testing this potential, results from initial efforts are encouraging. From the 18 oil recompletions we have performed to date in the Cherokee Basin, seven are currently producing oil, four will not produce oil and results are still pending on the remaining seven. The seven wells currently producing oil are flowing 26 net barrels a day in total. While it is too soon to draw broad conclusions, successful results in these initial tests could add up to 300 recompletion and 300 new well opportunities.

Results of Operations

Operating segment data for the periods indicated are as follows (in thousands):



                                         Three Months Ended
                                              March 31,                    Increase/
                                         2011           2012              (Decrease)
 Revenues
 Oil and gas sales                     $  20,237      $ 13,622      $  (6,615 )       (32.7 )%
 Gathering                                 1,356           699           (657 )       (48.5 )%

 Total production segment                 21,593        14,321         (7,272 )       (33.7 )%
 Pipeline segment                          3,173         3,428            255           8.0 %

 Total                                 $  24,766      $ 17,749      $  (7,017 )       (28.3 )%

 Operating profit
 Production                            $  13,130      $ (3,238 )    $ (16,368 )      (124.7 )%
 Pipelines                                   573         1,700          1,127         196.7 %

 Total segment operating profit           13,703        (1,538 )      (15,241 )      (111.2 )%
 General and administrative expenses      (4,888 )      (4,579 )          309          (6.3 )%
 Litigation reserve                       (9,500 )          -           9,500        (100.0 )%

 Total operating profit                $    (685 )    $ (6,117 )    $  (5,432 )      (793.0 )%

Three Months Ended March 31, 2011 Compared to the Three Months Ended March 31, 2012

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

                                                     Three Months Ended
                                                          March 31,                    Increase/
                                                     2011            2012              (Decrease)
                                                          ($ in thousands except per unit data)
Production Segment
Oil and gas sales                                 $    20,237      $ 13,622      $ (6,615 )       (32.7 )%
Gathering revenue                                 $     1,356      $    699      $   (657 )       (48.5 )%
Production expense                                $    12,434      $ 11,501      $   (933 )        (7.5 )%
Depreciation, depletion and amortization          $     5,951      $  6,162      $    211           3.5 %
Gain (loss) on disposal of assets                 $     9,922      $    104      $ (9,818 )       (99.0 )%
Production Data
Total production (Mmcfe)                                4,673         4,429          (244 )        (5.2 )%
Average daily production (Mmcfe/d)                       51.9          48.7          (3.2 )        (6.2 )%
Average Sales Price per Unit (Mcfe)
Natural Gas (Mcf)                                 $      4.08      $   2.73      $  (1.35 )       (33.1 )%
Oil(Bbl)                                          $     88.58      $  99.25      $  10.67          12.0 %
Natural Gas Equivalent (Mcfe)                     $      4.33      $   3.08      $  (1.25 )       (28.9 )%
Average Unit Costs per Mcfe
Production expense                                $      2.66      $   2.60      $  (0.06 )        (2.3 )%
Depreciation, depletion and amortization          $      1.27      $   1.39      $   0.12           9.4 %
Pipeline Segment
Pipeline revenue                                  $     3,173      $  3,428      $    255           8.0 %
Pipeline expense                                  $     1,660      $    882      $   (778 )       (46.9 )%
Depreciation and amortization expense             $       940      $    851      $    (89 )        (9.5 )%
Gain (loss) on disposal of asset                  $        -       $      5      $      5               *%

* Not meaningful

Oil and gas sales decreased $6.6 million, or 32.7%, from $20.2 million during the three months ended March 31, 2011 to $13.6 million during the three months ended March 31, 2012. Decreased average realized natural gas prices reduced revenue by $5.8 million and lower production volumes reduced revenue by $1.0 million. These decreases were slightly offset by increased oil production volumes and prices. Our average realized prices on an equivalent basis (Mcfe) decreased from $4.33 per Mcfe for the three months ended March 31, 2011, to $3.08 per Mcfe for the three months ended March 31, 2012. Oil and gas sales exclude any realized or unrealized hedging gains or losses.

Gathering revenue decreased $657,000, or 48.5%, from $1.4 million for the three months ended March 31, 2011 to $699,000 for the three months ended March 31, 2012. The decrease is primarily due to the settlement of the royalty lawsuits in late 2011 which lowered the rates that we are paid for gathering royalty interest gas. A decline in production volumes also contributed to the decrease.

Pipeline revenue increased $255,000, or 8.0%, from $3.2 million for the three months ended March 31, 2011 to $3.4 million for the three months ended March 31, 2012. The increase was due to higher volumes transported associated with oil production in Osage County, Oklahoma.

Production expense consists of lease operating expenses, production taxes and gathering expense. Production expense decreased $933,000, or 7.5%, from $12.4 million for the three months ended March 31, 2011, to $11.5 million for the three months ended March 31, 2012. The decrease was in part due to field optimization projects we began in the latter half of 2011, which resulted in decreased labor, vehicle and equipment costs of $741,000 and decreased gathering costs of $239,000. Also contributing to the decrease was a reduction in production taxes of $912,000 primarily due to lower gas prices and production. These reductions were offset by decreased capitalized expenses of $569,000 due to reduced drilling activity, a one-time charge of $368,000 related to our March 2012 field reorganization and a $22,000 increase across various other expense items. We believe that the field reorganization will result in annual savings of $2.0 million from reduced labor and equipment costs. Production costs were $2.66 per Mcfe for the three months ended March 31, 2011 as compared to $2.60 per Mcfe for the three months ended March 31, 2012. Excluding the one-time charge, production costs for the current quarter were $2.51 per Mcfe.

Pipeline expense decreased $778,000, or 46.9%, from $1.7 million during the three months ended March 31, 2011, to $882,000 during the three months ended March 31, 2012. Costs were higher in the prior year period due to $335,000 of costs related to an external gas leak and $261,000 of costs related to a pipeline capacity lease that was negotiated lower in January 2011 and finally expired at the end of October 2011.

Depreciation, depletion and amortization increased $122,000, or 1.8%, from $6.9 million during the three months ended March 31, 2011, to $7.0 million during the three months ended March 31, 2012. Depletion and amortization on our production properties increased approximately $211,000, or 3.5%, from $6.0 million during the three months ended March 31, 2011 to $6.2 million during the three months ended March 31, 2012. Increased depletion and amortization was primarily due to a higher depletion rate offset by lower production volumes in the current quarter. On a per unit basis, we had an increase of $0.12 per Mcfe from $1.27 per Mcfe during the three months ended March 31, 2011 to $1.39 per Mcfe during the three months ended March 31, 2012. Depreciation and amortization expense on our pipeline segment decreased $89,000, or 9.5%, from $940,000 during the three months ended March 31, 2011, to $851,000 during the three months ended March 31, 2012.

Gain from the disposal of assets of $9.9 million during the three months ended March 31, 2011, was primarily due to the second phase of the Appalachian Basin sale in January 2011.

General and administrative expenses decreased $309,000, or 6.3%, from $4.9 million during the three months ended March 31, 2011, to $4.6 million during the three months ended March 31, 2012. The decrease was primarily due to a $306,000 workman's compensation claim paid in the first quarter of 2011.

Litigation reserve expense was $9.5 million during the three months ended March 31, 2011. The expense was recorded to increase our litigation reserve to the estimated potential cost to resolve royalty owner lawsuits pending in Oklahoma and Kansas at the time. The Oklahoma lawsuit was settled in 2011 for $5.6 million which was paid in July 2011. The Kansas lawsuit was settled in 2011 for $7.5 million which included $3.0 million paid in January 2012 and $4.5 million to be paid by January 31, 2013. As part of these settlements, all ambiguity in the calculation of prospective as well as prior royalties in our lease agreements was eliminated. Subsequent to the settlements, we are charging post-production costs to royalty and overriding royalty interest owners pursuant to an agreed upon formula derived as part of the settlements.

Other income (expense) consists primarily of gains (losses) from derivative instruments, gains (losses) from equity investments and net interest expense. Gain from derivative financial instruments increased $12.8 million from a loss of $821,000 for the three months ended March 31, 2011, to a gain of $12.0 million for the three months ended March 31, 2012. We recorded unrealized losses of $10.0 million and $60,000 for the three months ended March 31, 2011 and 2012, respectively. We recorded realized gains of $9.2 million and $12.1 million for the three months ended March 31, 2011 and 2012, respectively. We recorded a mark-to market gain on our equity investment in Constellation Energy Partners LLC ("CEP") of $4.2 million for the three months ended March 31, 2012 with none recorded in the prior year quarter. Interest expense, net, was consistent year over year at $2.7 million for the three months ended March 31, 2011 and 2012, respectively.

Liquidity and Capital Resources

Cash flows from operating activities have historically been driven by the quantities of our production, the prices received from the sale of this production, and from our pipeline revenue. Prices of oil and gas have historically been very volatile and can significantly impact the cash from the sale of our production. Use of derivative financial instruments help mitigate this price volatility. Cash expenses also impact our operating cash flow and consist primarily of production operating costs, production taxes, interest on our indebtedness and general and administrative expenses.

Our primary sources of liquidity for the three months ended March 31, 2012, were cash generated from our operations and hedging activities, the sale of common stock to White Deer Energy L.P. and its affiliates ("White Deer") and borrowings under our borrowing base credit facility. At March 31, 2012, we had decreased our debt by $14.0 million from December 31, 2011.

Cash Flows from Operating Activities Cash flows provided by operating activities decreased $2.2 million from $12.6 million for the three months ended March 31, 2011, to $10.4 million for the three months ended March 31, 2012. The decrease was primarily the result of a decrease in revenues partially offset by an increase in gains from our commodity derivatives along with lower operating expenses.

Cash Flows from Investing Activities Cash flows used in investing activities were $2.7 million for the three months ended March 31, 2011, compared to $4.3 million for the three months ended March 31, 2012. Capital expenditures were $8.5 million and $4.5 million for the three months ended March 31, 2011 and 2012, respectively. Cash proceeds from the second phase of our Appalachian Basin sale in the first quarter of 2011 were $5.8 million. The following table sets forth our capital expenditures, including costs we have incurred but not paid, by major categories for the three months ended March 31, 2012 (in thousands):

                                              Three Months Ended
                                                March  31, 2012
                 Capital expenditures
                 Leasehold acquisition        $                62
                 Development                                2,479
                 Pipelines                                    113
                 Other items                                2,103

                 Total capital expenditures   $             4,757

Cash Flows from Financing Activities Cash flows used in financing activities totaled $10.6 million for the three months ended March 31, 2011, as compared to $6.5 million for the three months ended March 31, 2012. Debt repayments were $10.6 million and $14.0 million for the three months ended March 31, 2011 and 2012, respectively. During the first quarter of 2012, we issued $7.5 million of common stock to White Deer.

Sources of Liquidity in 2012 and Capital Requirements

We rely on our cash flows from operating activities as a source of internally generated liquidity. During the past three years, our cash flows from operating activities have been sufficient to fund our investing activities. 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 current depressed natural gas prices. To a lesser extent, we have in the past relied on the sale of our non-core production assets to generate liquidity. From time to time, we may also issue equity as an external source of liquidity. On February 9, 2012, we issued 2,180,233 shares of our common stock to White Deer for proceeds of $7.5 million which were used to retire the Secured Pipeline Loan and for other general corporate purposes.

At March 31, 2012, we have a $350 million secured borrowing base revolving credit facility with a borrowing base of $200 million. With borrowings of $179 million and $1.6 million in outstanding letters of credit, we had $19.4 million available under the facility on that date.

We are currently in discussions with our lenders regarding a borrowing base redetermination of the facility based on our oil and gas reserves at December 31, 2011. Primarily as a result of the decline in natural gas price assumptions and the roll off of gas hedges, the borrowing base is expected to be lowered no less than $23 million to $177 million. Given current gas prices, we do not anticipate having meaningful liquidity for some time. We expect to fund working capital and capital expenditures with cash flow from operations and cash on hand.

We have an effective $100 million universal shelf registration statement on Form S-3. We are initially limited to selling debt or equity securities under the shelf registration statement in one or more offerings over a 12 consecutive month period for a total initial public offering price not exceeding one third of our public equity float. The registration statement is intended to give us the flexibility to sell securities if and when market conditions and circumstances warrant, to provide funding for growth or other strategic initiatives, for debt reduction or refinancing and for other general corporate purposes. The actual amount and type of securities or combination of securities and the terms of those securities will be determined at the time of sale, if such sale occurs. If and when a particular series of securities is offered, the prospectus supplement relating to that offering will set forth our intended use of the net proceeds. In addition, we have entered into an at-the-market issuance sales agreement with a sales agent relating to the offering from time to time of shares of our common stock under the shelf registration statement. Sales of shares of our common stock, if any, may be made directly on the NASDAQ Global Market, on any other existing trading market for the common stock or through a market maker, or in privately negotiated transactions, subject to our approval. Our sales agreement is limited to the sale of up to a number of shares of common stock with an initial offering price not to exceed the amount that can be sold under the registration statement. As of the date of the sales agreement, such amount is limited to approximately $20.3 million. As of March 31, 2012, we had not issued any shares of common stock pursuant to the sales agreement.

We are continuing our strategic review of the KPC Pipeline. The review includes a potential sale of the asset which, if consummated, would generate cash and improve our liquidity. Potential buyers are currently engaged in due diligence.

During April 2012 we repriced the portion of our natural gas swap contracts expected to settle in June, July and August of 2012 to market prices for proceeds of $10.8 million. The proceeds will be utilized to reduce our debt.

Dilution

At March 31, 2012, including 2,180,233 shares of our common stock held by White Deer, we had 12,268,970 shares of common stock issued and outstanding. In addition, we have 22,915,155 outstanding warrants to purchase our common stock of which 22,241,333 are owned by White Deer at an average exercise price of $3.23 and 673,822 are owned by Constellation Energy Group Inc. at an average exercise price of $7.07. We also have 114,966 unvested restricted stock units and 1,140,620 options outstanding granted under our long term incentive plan. Consequently, if these securities were included as outstanding, our outstanding shares would have been 36,439,711 of which the warrants and common stock owned by White Deer represent approximately 67%. 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, purchase obligations and operating lease commitments. Except for the debt repayments during the first quarter of 2012, at March 31, 2012, there were no other material changes to our contractual commitments since December 31, 2011.

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, 2011, which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements. Our annual report on Form 10-K for the year ended December 31, 2011, is available on our website at www.pstr.com.

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