ITEM 2.
MANAGEMENTS 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 quarter of 2013, we drilled 55 new oil wells and recompleted 40 wells in the Cherokee Basin and recompleted two wells in Central Oklahoma. Capital spending during the three months ended
March 31, 2013, included $8.9 million on oil directed drilling and recompletions, $791,000 on maintenance related projects, including truck replacement and compressor optimization projects, and $378,000 to extend leases in the Cherokee Basin
and to acquire new acreage in Central Oklahoma. Oil production continues to increase from our oil directed development program. Net oil sales during the current quarter averaged 363 barrels a day, a 77% increase from the prior year quarter. In early
May 2013, our estimated net oil production exceeded 500 barrels per day. For the remainder of 2013 we plan to drill an additional 150 oil wells and recomplete an additional 20 wells in the Cherokee Basin. We also plan to recomplete seven wells and
drill five wells, including two horizontals, in Central Oklahoma. 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 climbed throughout the first quarter to approximately $4.00 per Mmbtu at quarter end. Subsequently, they have
continued to climb past $4.00 per Mmbtu. Despite current gas prices, we continue to maintain our curtailment of all capital expenditures related to natural gas development and will continue to focus on transitioning to a more balanced production
profile. This is a significant contributing factor to our 14% decline in gas and 76% increase in oil sales volumes when comparing the three month periods ended March 31, 2012 and 2013.
1
Three Months Ended March 31, 2012 Compared to the Three Months Ended March 31, 2013
The following table presents financial and operating data for the periods indicated as follows:
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Three Months Ended
March 31,
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Increase/
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2012
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2013
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(Decrease)
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($ in thousands except per unit data)
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Natural gas sales
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$
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11,774
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$
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12,442
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$
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668
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5.7
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%
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Crude oil sales
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$
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1,848
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$
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2,957
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$
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1,109
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60.0
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%
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Gathering revenue
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$
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699
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$
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654
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$
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(45
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)
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(6.4
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)%
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Production expense
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$
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11,501
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$
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9,775
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$
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(1,726
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)
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(15.0
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)%
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Depreciation, depletion and amortization
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$
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6,162
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$
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6,428
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$
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266
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4.3
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%
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Gain (loss) on disposal of assets
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$
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104
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$
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(31
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)
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$
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(135
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)
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*
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Sales Data
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Oil sales (Bbls)
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18,624
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32,679
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14,055
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75.5
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%
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Natural gas sales (Mmcf)
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4,318
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3,720
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(598
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)
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(13.8
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)%
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Total sales (Mmcfe)
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4,429
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3,917
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(512
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)
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(11.6
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)%
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Average daily sales (Mmcfe/d)
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48.7
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43.5
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(5.2
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)
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(10.6
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)%
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Average Sales Price per Unit
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Natural Gas (Mcf)
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$
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2.73
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$
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3.34
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$
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0.61
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22.3
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%
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Oil(Bbl)
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$
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99.25
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$
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90.49
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$
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(8.76
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)
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(8.8
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)%
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Natural Gas Equivalent (Mcfe)
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$
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3.08
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$
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3.93
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$
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0.85
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27.6
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%
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Average Unit Costs per Mcfe
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Production expense
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$
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2.60
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$
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2.50
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$
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(0.10
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)
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(3.8
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)%
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Depreciation, depletion and amortization
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$
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1.39
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$
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1.64
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$
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0.25
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18.0
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%
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Natural gas
sales increased $668,000, or 5.7%, from $11.8 million during the three months ended March 31, 2012, to $12.4 million during the three months ended March 31, 2013. Higher natural gas prices resulted in increased revenues of $2.3 million
while lower gas volumes partially offset that increase by $1.6 million. The decline in gas volumes was the result of a continued suspension of gas development as gas prices remain uneconomic during the first quarter as well as the natural decline of
our existing wells. Our average realized natural gas price increased from $2.73 per Mcf for the three months ended March 31, 2012, to $3.34 per Mcf for the three months ended March 31, 2013.
Oil revenue increased $1.1 million, or 60.0%, from $1.9 million during the three months ended March 31, 2012, to $3.0 million during
the three months ended March 31, 2013. Higher oil volumes resulted in increased revenues of $1.4 million while lower oil prices partially offset that increase by $286,000. Our average realized oil price decreased from $99.25 per barrel for the
three months ended March 31, 2012, to $90.49 per barrel for the three months ended March 31, 2013.
Gathering
revenue decreased $45,000, or 6.4%, from $699,000 for the three months ended March 31, 2012, to $654,000 for the three months ended March 31, 2013. The decrease is primarily due to lower gas volumes being transported as a result of our
14.1% natural gas production decline in the Cherokee Basin and 24.2% decline in third-party volumes transported. The decrease was partially offset by higher realized prices.
Production expense consists of lease operating expenses, severance and ad valorem taxes (production taxes) and gathering expense. Production expense decreased $1.7 million, or 15.0%, from
$11.5 million for the three months ended March 31, 2012, to $9.8 million for the three months ended March 31, 2013. The variance is driven by lower maintenance, electricity and labor costs of $1.0 million, one-time field restructuring
costs of $368,000 recognized in the prior-year period, and higher capitalized lease operating expenses of $162,000 as development activities increased. Production expense was $2.60 per Mcfe for the three months ended March 31, 2012, as compared
to $2.50 per Mcfe for the three months ended March 31, 2013. Excluding the one-time field restructuring costs, production expense for the three months ended March 31, 2012, was $2.51 per Mcfe.
2
Depreciation, depletion and amortization increased $266,000, or 4.3%, from $6.2 million
during the three months ended March 31, 2012, to $6.4 million during the three months ended March 31, 2013. On a per unit basis, we had an increase of $0.25 per Mcfe from $1.39 per Mcfe during the three months ended March 31, 2012, to
$1.64 per Mcfe during the three months ended March 31, 2013. The increase was primarily a result of an increase in the deprecation rate which was partially offset by lower volumes.
General and administrative expenses decreased $717,000, or 16.8%, from $4.3 million during the three months ended March 31, 2012, to
$3.5 million during the three months ended March 31, 2013. The decrease was primarily due to lower compensation costs of $482,000 coupled with lower legal and professional fees of $231,000. Compensation costs were lower, in part, due to cost
savings resulting from the restructuring of our Oklahoma City office in 2012.
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 $12.1 million for the three months ended March 31,
2012, compared to a realized loss of $873,000 for the three months ended March 31, 2013. The current quarter loss was due to realized losses on our Southern Star Basis swaps, and was 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 $4.00 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 unrealized losses
from derivative instruments of $60,000 and $6.2 million on our derivative contracts for the three months ended March 31, 2012 and 2013, respectively. We recorded mark-to-market gains on our equity investment in Constellation Energy Partners LLC
(CEP) of $4.2 million and $3.6 million for the three months ended March 31, 2012 and 2013, respectively. These gains are the result of improvements in the market price of CEPs traded units relative to the prior period.
Interest expense, net, was $2.7 million during the three months ended March 31, 2012, and $641,000 during the three months ended March 31, 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 this 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 three months ended March 31, 2013, were proceeds from issuing common stock and borrowings
under our borrowing base credit facility. At March 31, 2013, our debt increased by $8.5 million from December 31, 2012. The increase was primarily due to a $4.5 million royalty settlement payment and $1.1 million in property tax payments,
both which were made in December 2012 and funded in early 2013. The remaining increase funded our current capital expenditures and working capital needs.
Cash Flows from Operating Activities
Cash flows provided by operating
activities was $10.4 million for the three months ended March 31, 2012, compared to cash used of $2.8 million for the three months ended March 31, 2013. The decrease in cash was primarily a result of a decrease in realized gains from
commodity derivatives where $12.1 million in realized gains were generated in the prior year quarter compared to $873,000 in realized losses in the current quarter. In addition, a significant portion of cash was utilized in the current quarter to
fund the royalty settlement and property tax payments discussed above.
3
Cash Flows from Investing Activities
Cash flows used in investing activities were $4.3 million for the three months ended March 31, 2012, compared to cash used of $9.2
million for the three months ended March 31, 2013. The increased outflow was primarily due to higher capital expenditures which increased from $4.5 million during the three months ended March 31, 2012, to $9.2 million during the three
months ended March 31, 2013. Capital expenditures in the prior year quarter were lower compared to the current quarter as result of the steep decline in natural gas prices in early 2012 which prompted us to curtail gas related projects early in
the year and begin identifying viable oil development projects. Capital expenditures in the current quarter reflect our oil development activities in the Cherokee Basin. The following table sets forth our capital expenditures, including costs we
have incurred but not paid, by major categories for the three months ended March 31, 2013 (in thousands):
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Three Months Ended
March 31, 2013
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Capital expenditures
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Leasehold acquisition
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$
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378
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Development
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8,921
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Other items
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791
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Total capital expenditures
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$
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10,090
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Cash Flows from Financing Activities
Cash flows used in financing activities were $6.5 million for the three months ended March 31, 2012, as compared to cash received of
$11.6 million for the three months ended March 31, 2013. Debt repayments were $14.0 million for the three months ended March 31, 2012, compared to borrowings of $8.5 million for the three months ended March 31, 2013. During the three
months ended March 31, 2012, we issued $7.5 million of common stock to White Deer while $3.3 million of common stock was issued during the three months ended March 31, 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 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 $53.5
million, $53.4 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 proceeds of $32.5 million from issuing equity to White Deer. The proceeds from the sale
of our non-core assets and from equity issuances have generally been utilized to repay outstanding debt and for working capital purposes.
At March 31, 2013, we had a $200 million secured borrowing base revolving credit facility with a borrowing base of $90 million (the Borrowing Base Facility). We rely on this facility as
an external source of long and short-term liquidity. With borrowings of $66.0 million at March 31, 2013, we had $24.0 million available under the facility on that date. 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 May 8, 2013, with
borrowings of $73 million, we had $22 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.
4
We have an effective universal shelf registration statement on Form S-3. Pursuant to the
registration statement, we have implemented an at-the-market program under which shares of our common stock are sold. Through May 1, 2013, we sold under the program 2,578,962 shares of common stock for $3.9 million, net of $114,000 in agent
commissions during the year.
Dilution
At March 31, 2013, including 9,834,620 shares of our common stock held by White Deer, we had 23,732,480 shares of common stock issued and outstanding. In addition, we had 36,351,189 outstanding
warrants to purchase our common stock of which 35,901,974 are owned by White Deer at an average exercise price of $2.62 and 449,215 are owned by Constellation Energy Group Inc. at an average exercise price of $7.32. We also had 149,988 restricted
stock units and 2,455,663 options outstanding granted under our long-term incentive plan. Consequently, if these securities were included as outstanding, our outstanding shares would have been 62,689,320 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 three months ended March 31, 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 $1.5 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 three months ended March 31, 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:
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current weak economic conditions;
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volatility of oil and natural gas prices;
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increases in the cost of drilling, completion and gas gathering or other costs of developing and producing our reserves;
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access to capital, including debt and equity markets;
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results of our hedging activities;
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drilling, operational and environmental risks; and
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regulatory changes and litigation risks.
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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, 2012, 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, 2012, 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.