PSTRQ PostRock Energy Corporation (CE)

Highlights

• Based on a 21:1 oil-to-gas economic equivalency, production increased over 2% from the prior year; at the traditional 6:1 oil-to-gas energy equivalency, production declined 5%.
• Revenue totaled $83.5 million, up 16% from the prior year.
• Total operating expenses, including lease operating, gathering, production taxes and general and administrative expenses, decreased $1.3 million from the prior year.
• Bank debt decreased 10% to $83 million.
• Cost reduction initiatives implemented subsequent to year-end are expected to further reduce costs by nearly $4.0 million annually.
• The 2015 capital budget is set at $5.4 million, a reduction of over 85% from the prior year.
• The Company has engaged Evercore Group L.L.C. to assist the Board in evaluating strategic alternatives.

Operations

Central Oklahoma – Net daily production for the year averaged 538 barrels and 321 Mcf per day. At the traditional 6:1 equivalency and at a 21:1 economic equivalency, total production increased 162% and 147%, respectively, over the prior-year period. During 2014, the Company performed 13 recompletions and drilled four Hunton horizontal wells. The first two Hunton horizontal wells were placed on production at roughly mid-year and reached peak production of 600 BOPD and 230 BOPD, respectively. The last two Hunton horizontal wells were placed on production in the fourth quarter and reached peak production of 330 BOPD and 275 BOPD, respectively. Combined, the four Hunton wells cost approximately $14.0 million. Through March 2, 2015, they have produced just over 107,000 gross barrels of oil, 83,200 barrels net. Using actual revenue received through January and projected production at recent strip prices, the combined IRR for these wells should approximate 20%.

In June, the Company entered into a joint venture with Silver Creek Oil & Gas, LLC covering approximately 17,900 gross acres in Cleveland and Pottawatomie Counties in Central Oklahoma. The Company participated in drilling two Woodford horizontal wells which were put on production early in the fourth quarter. Unfortunately, results to date have been very disappointing. The Company has a 30% interest in the wells and spent roughly $2.5 million on them.

Cherokee Basin –Net daily production during the year averaged 34.6 MMcf and 183 barrels, 10% and 30%, respectively, below the prior-year period. By the fourth quarter, the gas decline had moderated to 8% versus the 11-13% historic decline rate. The reduction is largely a result of compression fuel savings from the Cherokee Basin compression reconfiguration completed during the second quarter of 2014.

Subsequent to year-end – In response to the recent collapse of oil and gas prices, the Company reduced its Oklahoma City staff by nearly 25% and its field staff by nearly 20%. These and other savings initiatives are expected to result in annualized savings of approximately $4.0 million in expenses. We set our 2015 capital budget at $5.4 million, an 86% reduction from 2014. The budget includes only maintenance capital and completion of development projects under way at year-end 2014. At current prices, we do not plan any additional drilling in 2015. However, this could change if oil and gas prices recover. Excess cash flow is expected to be used to reduce outstanding debt. In February we engaged Evercore Group L.L.C. to help evaluate strategic alternatives.

2014 Results

Revenue increased 16% from the prior year to $83.5 million. Despite lower sales volumes, gas revenue increased 9% to $56.3 million. The increase was driven by a 20% increase in realized prices to $4.25 per Mcf. Oil revenue increased 35% to $24.5 million, as production increased 43%. The production increase was partially offset by a 6% lower realized price of $89.23 per barrel. Gas gathering revenue increased 3% to $2.7 million, as higher gas prices offset lower volumes.

Production costs, including lease operating expenses, gathering costs and production taxes, increased 2% to $40.9 million, or $2.75 per Mcfe at a 6:1 rate or $2.15 per Mcfe at a 21:1 economic equivalency rate. An increase in production taxes of $700,000 was the main contributor to the increase. Operating costs in Central Oklahoma increased by $2.3 million as the Company's development focus shifted from the Cherokee Basin to Central Oklahoma. The increase was largely offset by a $2.2 million reduction in costs in the Cherokee Basin, driven by the compressor reconfiguration project.

General and administrative expenses decreased 13% from the prior year to $13.9 million. Excluding $1.6 million of legal fees related to litigation and a $454,000 workman's compensation charge, both expensed in 2013, general and administrative expenses for 2014 were roughly equal to the prior year's total.

The Company realized a $3.9 million hedging loss for the year compared to a $2.3 million loss in the prior-year period. A $20.3 million mark to market gain on derivative contracts for the year was recognized compared to $1.7 million in the prior-year period.

As a result of the restatement discussed below, the Company's Series A preferred stock was moved from temporary equity to debt on the balance sheet. As a result, accretion and paid-in-kind dividends associated with this preferred stock was reported as $14.8 million and $16.1 million of non-cash interest expense for the years ended December 31, 2013 and 2014, respectively. Interest expense accrued based on the amount borrowed under the Company's revolving credit facility was approximately $3.6 million, an increase over the prior-year period as average bank debt outstanding was higher when compared to the prior-year period's average. Despite the higher average bank debt for the year, the total outstanding bank debt decreased by $9.0 million at the end of 2014 compared with the prior year.

Due to appreciation of the market price of the CEP units in 2014, a mark-to-market gain of $1.8 million was recorded. The Company also realized a $5.4 million gain on the sale of the units.

Net income for the year, driven by the items discussed above, was $3.9 million, compared to a $23.4 million loss in the prior-year period. Excluding mark-to-market gains and losses on our derivatives and equity investments, we had a loss of $18.3 million in 2014 compared to a loss of $31.8 million in the prior-year period.

Fourth Quarter Results

Production, on a 6:1 equivalency basis, decreased from the prior-year quarter by 2%. Production, at the fourth quarter's 18:1 economic equivalency, increased 4%. Oil production increased 38% to 835 BOPD while gas production declined by 6.2% to 36 MMcf per day.

Revenue increased 4% from the prior-year period to $18.8 million. Despite a 6% decrease in sales volumes, to 36.0 MMcf per day, natural gas revenue increased 5% from the prior-year period to $12.8 million due to a 12% increase in realized prices to $3.87 per Mcf. Oil revenue increased 3% from the prior-year period to $5.4 million as production increased 38%. The increase was partially offset by a 25% lower realized price of $70.51 per barrel. Gas gathering revenue decreased 3% to $588,000 as lower volumes more than offset higher gas prices.

Production costs decreased 4% from the prior-year period to $9.2 million. The majority of the decrease was a result of lower operating costs in the Cherokee Basin of $592,000 due to reduced compressor rentals. This was partially offset by higher costs in Central Oklahoma of $156,000 resulting from the increased development during the year. In total, production costs were $2.45 an Mcfe, compared to $2.49 an Mcfe in the prior-year period.

General and administrative expenses decreased 31% from the prior-year period to $3.3 million. Excluding $1.5 million of legal fees related to the litigation with CEP expensed in 2013, general and administrative expenses were roughly unchanged from the prior year's adjusted total.

Accretion and paid-in-kind dividends associated with the Series A preferred stock was reported as $4.0 million of interest expense for the quarter. This was at a lower rate than in the past due to the Preferred Exchange, discussed in more detail below, which occurred in the fourth quarter. Interest expense accrued based on the amount borrowed under the Company's revolving credit facility was approximately $811,000, a decrease of 15% over the prior-year period as the average bank debt outstanding was lower when compared to the prior-year period's average.

The Company had a $666,000 realized hedging gain in the quarter compared to a gain of $77,000 in the prior-year period.

Due to depreciation of the market price of CEP units in the fourth quarter, a mark-to-market loss of $2.2 million was recorded. The Company recognized a realized gain of $4.8 million on the sale of units.

Net income for the quarter was $14.5 million compared to a $10.8 million loss in the prior-year period. Excluding mark-to-market gains and losses on our derivatives and equity investments, we had a loss of $491,000 in 2014 compared to a loss of $8.8 million in the prior year period.

Restatement

On March 20, 2015, the Company concluded that its audited consolidated financial statements and related consolidated financial information for each quarter and annual period end, beginning with September 30, 2010 through September 30, 2014 should no longer be relied upon because of a misclassification of the Company's Series A Preferred Stock on its consolidated balance sheet. The Company intends to correct the error with restated consolidated financial statements and related consolidated financial information in the Company's Annual Report on Form 10-K for the year ended December 31, 2014. The effect of the restatement on the Company's consolidated balance sheets for each quarter and annual period end, beginning with September 30, 2010, consists of non-cash reclassifications of the Series A Preferred Stock from temporary equity to a liability. Additionally, dividends and accretion, originally taken to Additional paid-in capital, have been reclassified to Interest Expense on the statement of operations. While these non-cash reclassifications have the effect of reducing net income (or increasing the net loss) in each period, they have no material impact on total stockholders' equity, net income (loss) attributable to common stockholders, net income (loss) per common share or cash flows.

More information on the restatement is disclosed in our Item 402 on Form 8-K dated March 24, 2015 and in Note 20 of the Company's 2014 Annual Report on Form 10K.

Reverse Stock Split

On January 2, 2015, the Company's common stock was reverse split on a 1-for-10 basis. Common stock, warrants, or per share amounts presented in this release have been adjusted to reflect the reverse stock split.

Hedges

The Company's natural gas and crude oil swaps for 2015 cover an average of 24.6 MMcf and 195 Bbls per day at a weighted average price of $4.01 and $92.73, respectively. This represents approximately 73% and 28% of anticipated gas and oil production, respectively. The following table summarizes the Company's derivative positions at December 31, 2014.

Debt

At December 31, 2014, $83.0 million was drawn under the Company's revolving credit facility, a decrease of $9.0 million from the prior year and a $3.0 million increase from September 30, 2014. At March 2, 2015, $83.5 million was drawn under the revolving credit facility.

On October 9, 2014, PostRock issued 3.2 million shares of common stock to White Deer in exchange for $35.0 million of the Company's Series A preferred stock (the "Preferred Exchange"). This eliminated roughly one-third of White Deer's preferred position.

On July 17, 2014, White Deer extended the date through which the Company may pay the preferred dividends in-kind to June 30, 2016. On December 30, PostRock paid in-kind a quarterly dividend on its preferred. This increased the liquidation value of the preferred by $2.4 million to $79.8 million. White Deer also received 556,388 additional warrants with a weighted average strike price of $4.36 a share. At December 30, White Deer held a total of 3.3 million warrants exercisable at an average price of $13.00 a share and 4.3 million common shares.

CEP Investment

During 2014, the Company sold 5,054,255 CEP Class B units at a weighted average price of $2.72 per unit. The value of the Company's investment in CEP reached zero in the fourth quarter; therefore, the Company recorded a realized gain of approximately $5.4 million in 2014. As of December 31, 2014, the Company owned 224,850 Class B units, which were disposed of in February 2015 for approximately $290,000.

Capital Expenditures

During the fourth quarter, capital expenditures totaled $13.1 million. This included $12.1 million spent on development. The remaining $1.0 million was spent on maintenance, geological and geophysical, and land expenditures.

Capital expenditures for the year totaled $37.5 million in 2014. This included $27.0 million spent on exploration and development, $5.8 million on maintenance expenditures, including the compressor optimization project, and acquisition and geological and geophysical expenditures of $1.8 million and $1.4 million, respectively.

Reserves

Based on a 6:1 oil-to-gas conversion, proved reserves increased 28% to 143.9 Bcfe at year end. Gas reserves increased 32.5 Bcf, or 38%, primarily driven by increased prices year-over-year. Oil reserves decreased approximately 250,000 barrels, or 6%, primarily driven by lower oil prices and higher operating costs year-over-year coupled with roll-off of production. At year-end, approximately 68% of the Company's reserves were classified as proved developed.

PostRock will host its quarterly webcast and conference call tomorrow, Tuesday, March 31, 2015, at 10:00 a.m. Central Time. The live webcast will be accessible on the 'Investors' page at www.pstr.com, where it will also be available for replay. The conference call number for participation is (866) 516-1003.

PostRock Energy Corporation is engaged in the acquisition, exploration, development, production and gathering of crude oil and natural gas. Its primary activity is focused in the Cherokee Basin, a 15-county region in southeast Kansas and northeast Oklahoma, and in Central Oklahoma. The Company owns and operates over 3,000 wells and maintains nearly 2,200 miles of gas gathering lines primarily in the Cherokee Basin.

Forward-Looking Statements

Opinions, forecasts, projections or statements, other than statements of historical fact, are forward-looking statements that involve risks and uncertainties. Forward-looking statements in this announcement are made pursuant to the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance such expectations will prove correct. Actual results may differ materially due to a variety of factors, some of which may not be foreseen. These risks and other risks are detailed in the Company's filings with the Securities and Exchange Commission, including risk factors listed in the Annual Report on Form 10-K and other filings. The Company's SEC filings may be found at www.pstr.com or www.sec.gov. By making these forward-looking statements, the Company undertakes no obligation to update these statements for revisions or changes.

Reconciliation of Non-GAAP Financial Measures

The following table represents a reconciliation of net income (loss) to EBITDA and adjusted EBITDA, as defined, for the periods presented.

Although adjusted EBITDA is not a measure of performance calculated in accordance with generally accepted accounting principles, or GAAP, management considers it an important measure of performance. Adjusted EBITDA is not a substitute for the GAAP measures of earnings or cash flow and is not necessarily a measure of the Company's ability to fund its cash needs. In addition, it should be noted that companies calculate adjusted EBITDA differently, and therefore adjusted EBITDA as presented herein may not be comparable to adjusted EBITDA reported by other companies. Adjusted EBITDA has material limitations as a performance measure because it excludes, among other things, (a) interest expense, which is a necessary element of business to the extent that an entity incurs debt, (b) depreciation, depletion and amortization, which are necessary elements of any business that uses capital assets, (c) impairments of oil and gas properties, which may at times be a material element of an independent oil company's business, and (d) income taxes, which may become a material element of the Company's operations in the future. Because of its limitations, adjusted EBITDA should not be considered a measure of discretionary cash available to invest in the growth of PostRock's business.

CONTACT: Company Contact:
         Stephen L. DeGiusti
         EVP, General Counsel & Secretary
         sdegiusti@pstr.com
         (405) 702-7420

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