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| PSTR > SEC Filings for PSTR > Form 10-Q on 9-Nov-2011 | All Recent SEC Filings |
9-Nov-2011
Quarterly Report
• Closed on the second and third phases of our Appalachia Basin sale for $11.7 million and $4.9 million, respectively.
• Reduced debt by $24.2 million from December 31, 2010, including the full settlement of our QER Loan.
• Settled all of our Oklahoma royalty interest owner lawsuits for $5.6 million which was funded in July 2011 and reached a preliminary settlement of our Kansas royalty owner class action lawsuit for $7.5 million.
• Brought 93 new oil and gas wells online in the Cherokee Basin, 10 of which were drilled prior to 2011. Recompleted 83 wells and returned 53 wells in the Basin to production.
2011 Drilling and Development Update
We budgeted $43.6 million for drilling and development in 2011. During the
first three quarters of 2011, we drilled and connected 83 development wells,
completed 10 new wells drilled in prior periods, recompleted or connected 83
wells and returned 53 wells to production in the Cherokee Basin. We have spent
$20.6 million for drilling and development through September 30, 2011, compared
to $35.8 million budgeted. During the fourth quarter, we expect to drill,
complete, and connect approximately 15 wells, primarily to retain acreage. Our
decision to spend less on development activity is due to the decline in gas
prices and the even greater need to better understand results of our drilling
activity. We are focused on improving rates of return on our development
activity by reducing expenses while improving performance of newly drilled wells
and recompletions.
CEP Investment
On August 8, 2011, we acquired, from Constellation Energy Group, Inc.
("CEG"), a 14.9% voting interest in CEP and the right to appoint two directors
to CEP's Board. The total cost of the investment was $11.5 million, including
$6.6 million of cash, 1,000,000 shares of our common stock with a fair value of
$4.1 million and warrants to acquire an additional 673,822 shares of our common
stock with a fair value of $518,000, and acquisition costs of $283,000. Of the
warrants, 224,607 are exercisable for one year following issuance at an exercise
price of $6.57 a share, 224,607 are exercisable for two years following issuance
at $7.07 a share and 224,608 for three years following issuance at $7.57 a
share. The 14.9% voting interest consisted of 485,065 of CEP's outstanding Class
A Member Interests, representing all of the class, and 3,128,670 Class B Member
Interests, representing 13.2% of the class at the time. The Class B Member
Interests are traded on the New York Stock Exchange under the ticker "CEP" with
a closing price of $2.78 per unit at September 30, 2011.
CEP is focused on the acquisition, development and production of oil and
natural gas properties as well as related midstream assets. All of its proved
reserves are located in the Cherokee Basin in Kansas and Oklahoma, the Black
Warrior Basin in Alabama, the Woodford Shale in the Arkoma Basin in Oklahoma and
the Central Kansas
Uplift in Kansas and Nebraska. Because we and CEP each have the majority of their assets in the Cherokee Basin of Kansas and Oklahoma, the investment was made in an attempt to increase the likelihood of improved efficiencies in this region through cooperation with CEP and others.
We account for our investment in CEP at fair value and recognize the change
in fair value in our results of operations.
Results of Operations
In March 2010, PostRock completed the recombination of its three predecessor
entities. The results of operations for the nine months ended September 30,
2010, represent the combined results of these predecessor entities and PostRock.
The results of operations for all other periods presented are those of PostRock.
Unless the context requires otherwise, references to the "Company," "we," "us"
and "our" refer to PostRock and its subsidiaries from the date of the
recombination and to the three predecessor entities on a consolidated basis
prior thereto. Operating segment data for the periods indicated are as follows
(in thousands):
Three Months Ended Nine Months Ended
September 30, September 30,
2010 2011 2010 2011
Revenues
Oil and gas sales $ 21,484 $ 20,543 $ 68,734 $ 62,305
Gathering 1,437 1,383 4,417 4,272
Total production segment 22,921 21,926 73,151 66,577
Pipeline segment 2,402 2,501 7,310 8,140
Total $ 25,323 $ 24,427 $ 80,461 $ 74,717
Operating profit
Production $ 8,019 $ 4,239 $ 24,886 $ 25,498
Pipelines 104 484 (116 ) 1,289
Total segment operating profit 8,123 4,723 24,770 26,787
General and administrative expenses (4,638 ) (4,241 ) (19,867 ) (14,277 )
Recovery of misappropriated funds, net 997 - 997 -
Litigation reserve (20 ) (1,981 ) (1,640 ) (11,581 )
Total operating profit $ 4,462 $ (1,499 ) $ 4,260 $ 929
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Three Months Ended September 30, 2010 Compared to the Three Months Ended
September 30, 2011
The following table presents financial and operating data for the periods
indicated as follows:
Three Months Ended
September 30, Increase/
2010 2011 (Decrease)
($ in thousands except per unit data)
Production Segment
Oil and gas sales $ 21,484 $ 20,543 $ (941 ) (4.4 )%
Gathering revenue $ 1,437 $ 1,383 $ (54 ) (3.8 )%
Production expense $ 10,904 $ 11,845 $ 941 8.6 %
Depreciation, depletion and amortization $ 4,007 $ 5,874 $ 1,867 46.6 %
Gain (loss) on sale of assets $ 9 $ 32 $ 23 255.6 %
Production Data
Total production (Mmcfe) 4,956 4,728 (228 ) (4.6 )%
Average daily production (Mmcfe/d) 53.9 51.4 (2.5 ) (4.6 )%
Average Sales Price per Unit (Mcfe)
Natural Gas (Mcf) $ 4.14 $ 4.10 $ (0.04 ) (1.0 )%
Oil(Bbl) $ 71.63 $ 84.68 $ 13.05 18.2 %
Natural Gas Equivalent (Mcfe) $ 4.34 $ 4.35 $ 0.01 0.2 %
Average Unit Costs per Mcfe
Production expense $ 2.20 $ 2.51 $ 0.31 14.1 %
Depreciation, depletion and amortization $ 0.81 $ 1.24 $ 0.43 53.1 %
Pipeline Segment
Pipeline revenue $ 2,402 $ 2,501 $ 99 4.1 %
Pipeline expense $ 1,431 $ 1,132 $ (299 ) (20.9 )%
Depreciation and amortization expense $ 867 $ 881 $ 14 1.6 %
Gain (loss) on sale of assets $ - $ (4 ) $ (4 ) * %
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* Not meaningful
Oil and gas sales decreased $941,000, or 4.4%, from $21.4 million during the
three months ended September 30, 2010, to $20.5 million during the three months
ended September 30, 2011. Lower production volumes resulted in a $990,000
decrease, partially offset by higher realized natural gas equivalent prices,
which resulted in a $49,000 increase. Production decreased due to the
divestiture of the Appalachia Basin assets and reduced production volumes in the
Cherokee Basin. The Cherokee Basin reduction is due to lower than planned
development activity, as discussed earlier, and natural production declines.
Production related to divested Appalachian assets was 52 Mmcfe or 0.6 Mmcfe/d in
the prior year period. Driven by higher realized oil prices, our average
realized natural gas equivalent prices increased from $4.34 per Mcfe for the
three months ended September 30, 2010, to $4.35 per Mcfe for the three months
ended September 30, 2011.
Gathering revenue decreased $54,000, or 3.8%, from $1.44 million for the
three months ended September 30, 2010, to $1.38 million for the three months
ended September 30, 2011, primarily due to a decline in transported volumes. We
expect gathering revenue to decrease substantially following resolution of our
Kansas royalty owner litigation.
Pipeline revenue increased $99,000, or 4.1%, from $2.4 million for the three
months ended September 30, 2010, to $2.5 million for the three months ended
September 30, 2011. The increase was primarily due to increased volumes
transported on the system and higher commodity revenue.
Production expense consists of lease operating expenses, severance and ad
valorem taxes (collectively, "production taxes") and gathering expense.
Production expense increased $941,000, or 8.6%, from $10.9 million for the three
months ended September 30, 2010, to $11.8 million for the three months ended
September 30, 2011. Production taxes increased $1.1 million from $649,000 for
the three months ended September 30, 2010, to $1.8 million for the three months
ended September 30, 2011. Production taxes were lower in the prior year quarter
as ad valorem taxes were revised to reflect lower reserve values assessed by
taxing authorities in 2010. The increase in production taxes was offset by a
decrease in lease operating expenses. Lease operating expenses decreased
$196,000 from $10.3 million for the three months ended September 30, 2010 to
$10.1 million for the three months ended September 30, 2011. Excluding
production taxes, production expense was $2.07 per Mcfe for the three months
ended September 30, 2010, as compared to $2.13 per Mcfe for the three months
ended September 30, 2011. There are several projects underway to reduce expenses
and improve performance on wells, which is expected to have a positive impact on
our cost per Mcfe.
Pipeline expense decreased $299,000, or 20.9%, from $1.4 million during the
three months ended September 30, 2010, to $1.1 million during the three months
ended September 30, 2011. The decrease was primarily due to a significant
reduction in costs related to our December 2010 partial termination of a
capacity lease. The capacity lease subsequently expired at the end of October
2011.
Depreciation, depletion and amortization increased $1.9 million, or 38.6%,
from $4.9 million during the three months ended September 30, 2010, to
$6.8 million during the three months ended September 30, 2011. This increase is
the result of including the gathering system in our full cost pool beginning in
the fourth quarter of 2010 which accelerated the gathering system's depletion
under the units of production method. The gathering system was previously a
component of our pipeline segment and depreciated under the straight line
method.
Litigation reserve was $20,000 for the three months ended September 30, 2010,
and $2.0 million for the three months ended September 30, 2011. The expense in
2011 was related to our Kansas royalty owner lawsuit. A settlement was reached
for our Kansas royalty owner litigation in September 2011. Under the terms of
the settlement, we will pay claimants a total of $7.5 million. An initial
$3.0 million payment is required within 30 days after final court approval is
granted, which is currently anticipated in December 2011. The remaining payment
of $4.5 million will be due one year thereafter. Our reserve for the litigation
reflects the present value of both payments of approximately $7.0 million.
Recovery of misappropriated funds was $1.0 million for the three months ended
September 30, 2010. The amount represents recovery of a portion of funds
misappropriated between 2005 and 2007 by former officers, as more fully
described in our Annual Report on Form 10-K for the year ended December 31,
2010.
General and administrative expenses decreased $397,000, or 8.6%, from
$4.6 million during the three months ended September 30, 2010, to $4.2 million
during the three months ended September 30, 2011. The decrease was primarily due
to lower legal and board fees following our September 2010 refinancing,
partially offset by $757,000 of office closure costs recorded during the period
upon securing a sublease for our Houston office which was previously
consolidated with our Oklahoma City office.
Other income was $23.7 million during the three months ended September 30,
2010, compared to $25.7 million during the three months ended September 30,
2011. Gain from derivative financial instruments was $32.3 million during the
three months ended September 30, 2010, compared to $12.0 million during the
three months ended September 30, 2011. We recorded a $25.5 million unrealized
gain and $6.8 million realized gain on our derivative contracts for the three
months ended September 30, 2010, compared to a $4.7 million unrealized gain and
$7.3 million realized gain for the three months ended September 30, 2011.
Interest expense, net, was $8.6 million during the three months ended
September 30, 2010, and $2.6 million during the three months ended September 30,
2011. The decrease is primarily due to the September 2010 refinancing which
resulted in a lower balance of debt, lower interest rates and decreased
amortization of debt issuance costs. The loss from investment in affiliate was
$859,000 during the three months ended September 30, 2011, which was due to a
decline in the fair value of our investment in CEP.
Nine Months Ended September 30, 2010 Compared to the Nine Months Ended
September 30, 2011
The following table presents financial and operating data for the periods
indicated as follows:
Nine Months Ended
September 30, Increase/
2010 2011 (Decrease)
($ in thousands except per unit data)
Production Segment
Oil and gas sales $ 68,734 $ 62,305 $ (6,429 ) (9.4 )%
Gathering revenue $ 4,417 $ 4,272 $ (145 ) (3.3 )%
Production expense $ 35,672 $ 35,685 $ 13 * %
Depreciation, depletion and amortization $ 12,462 $ 17,780 $ 5,318 42.7 %
Gain (loss) on sale of assets $ (131 ) $ 12,386 $ 12,517 * %
Production Data
Total production (Mmcfe) 14,696 14,142 (554 ) (3.8 )%
Average daily production (Mmcfe/d) 53.8 51.8 (2.0 ) (3.7 )%
Average Sales Price per Unit (Mcfe)
Natural Gas (Mcf) $ 4.50 $ 4.14 $ (0.36 ) (8.0 )%
Oil(Bbl) $ 73.62 $ 91.14 $ 17.52 23.8 %
Natural Gas Equivalent (Mcfe) $ 4.68 $ 4.41 $ (0.27 ) (5.8 )%
Average Unit Costs per Mcfe
Production expense $ 2.43 $ 2.52 $ 0.09 3.7 %
Depreciation, depletion and amortization $ 0.85 $ 1.26 $ 0.41 48.2 %
Pipeline Segment
Pipeline revenue $ 7,310 $ 8,140 $ 830 11.4 %
Pipeline expense $ 4,842 $ 4,148 $ (694 ) (14.3 )%
Depreciation and amortization expense $ 2,584 $ 2,702 $ 118 4.6 %
Gain (loss) on disposal of asset $ - $ (1 ) $ (1 ) * %
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* Not meaningful
Oil and gas sales decreased $6.4 million, or 9.4%, from $68.7 million during
the nine months ended September 30, 2010, to $62.3 million during the nine
months ended September 30, 2011. Lower production volumes resulted in a
$2.6 million decrease and lower realized natural gas equivalent prices resulted
in a $3.8 million decrease. Production decreased due to the divestiture of the
Appalachia Basin assets and reduced production volumes in the Cherokee Basin.
Production related to divested Appalachian assets was 190 Mmcfe or 0.7 Mmcfe/d
in the prior year period. The Cherokee Basin reduction is due to lower than
planned development activity, as discussed earlier, and natural production
declines. Our average realized natural gas equivalent prices decreased from
$4.68 per Mcfe for the nine months ended September 30, 2010, to $4.41 per Mcfe
for the nine months ended September 30, 2011 as lower realized natural gas
prices more than offset higher realized oil prices.
Gathering revenue decreased $145,000, or 3.3%, from $4.4 million for the nine
months ended September 30, 2010, to $4.3 million for the nine months ended
September 30, 2011, primarily due to a decline in transported volumes. We expect
gathering revenue to decrease substantially following resolution of our Kansas
royalty owner litigation.
Pipeline revenue increased $830,000, or 11.4%, from $7.3 million for the nine
months ended September 30, 2010, to $8.1 million for the nine months ended
September 30, 2011. The increase was primarily due to increased volumes
transported on the system and higher commodity revenue.
Production expense was flat at $35.7 million for the nine months ended
September 30, 2010 and 2011. An increase in lease operating expenses of
approximately $500,000 was offset by a decrease in production taxes of the same
magnitude. The increase in lease operating expense was primarily due to higher
oil well workover costs. Production expense was $2.43 per Mcfe for the nine
months ended September 30, 2010, as compared to $2.52 per Mcfe for the nine
months ended September 30, 2011.
Pipeline expense decreased $694,000, or 14.3%, from $4.8 million during the
nine months ended September 30, 2010, to $4.1 million during the nine months
ended September 30, 2011. The decrease was primarily due to a significant
reduction in costs related to our December of 2010 partial termination of a
capacity lease that was partially offset by the costs associated with gas lost
in the first quarter of 2011 due to an external corrosion leak.
Depreciation, depletion and amortization increased $5.4 million, or 36.1%,
from $15.0 million during the nine months ended September 30, 2010, to $20.5
million during the nine months ended September 30, 2011. As noted above,
beginning in the fourth quarter of 2010, the gathering system was included in
our full cost pool and depreciated under the units of production method. This
change drove an increase in depletion and amortization of approximately $5.3
million. Depreciation and amortization expense on our pipeline segment increased
$118,000, or 4.6%, from $2.6 million during the nine months ended September 30,
2010, to $2.7 million during the nine months ended September 30, 2011.
Gain from the sale of assets of $12.4 million during the nine months ended
September 30, 2011, was primarily due to the second and third phases of the
Appalachia Basin sale in 2011. Gross proceeds from both phases were
$16.6 million.
General and administrative expenses decreased $5.6 million, or 28.1%, from
$19.9 million during the nine months ended September 30, 2010, to $14.3 million
during the nine months ended September 30, 2011. Our March 2010 recombination
and the September 2010 refinancing have enabled us to eliminate significant
overhead costs. Partially offsetting the decrease are the Houston office closure
costs discussed above.
Litigation reserve increased $9.9 million, from $1.7 million during the nine
months ended September 30, 2010, to $11.6 million during the nine months ended
September 30, 2011. The $1.7 million expense for the nine months ended
September 30, 2010, was primarily related to shareholder related lawsuits that
were settled in early 2011. The $11.6 million expense for the nine months ended
September 30, 2011, was for an increase to the estimated potential cost to
resolve royalty owner lawsuits pending in Oklahoma and Kansas. These represent
the last known significant contingent liabilities remaining from our predecessor
entities. All of our Oklahoma royalty owner lawsuits were settled and funded in
July 2011 for $5.6 million. The settlement of our Kansas royalty owner lawsuit
will require a $3.0 million payment within 30 days after final Court approval is
granted and a $4.5 million payment one year thereafter. The present value of
both payments is estimated to be $7.0 million. The expense recorded in 2011 for
this lawsuit established the $5.6 million reserve for the Oklahoma lawsuit and
increased the reserve for the Kansas lawsuit to $7.0 million at September 30,
2011.
Recovery of misappropriated funds was $1.0 million for the nine months ended
September 30, 2010. The amount represents recovery of a portion of funds
misappropriated between 2005 and 2007 by former officer.
Other income was $53.1 million during the nine months ended September 30,
2010, compared to $27.0 million during the nine months ended September 30, 2011.
Gain from derivative financial instruments was $75.5 million during the nine
months ended September 30, 2010, compared to $16.7 million during the nine
months ended September 30, 2011. We recorded a $54.4 million unrealized gain and
$21.1 million realized gain on our derivative contracts for the nine months
ended September 30, 2010, compared to a $6.5 million unrealized loss and
$23.2 million realized gain for the nine months ended September 30, 2011.
Interest expense, net, was $22.4 million during the nine months ended
September 30, 2010, and $7.9 million during the nine months ended September 30,
2011. The decrease is primarily due to the September 2010 refinancing, which
resulted in lower debt balances, lower interest rates and decreased amortization
of debt issuance costs. Gain from forgiveness of debt was $1.6 million during
the nine months ended September 30, 2011. The gain was a result of the
settlement of our QER Loan under a troubled debt restructuring as discussed in
Liquidity and Capital Resources - QER Loan below. The loss from investment in
affiliate was $859,000 during the nine months ended September 30, 2011, which
was due to a decline in the fair value of our investment in CEP.
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 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 nine months ended September 30,
2011, were cash generated from our operations and commodity derivatives, cash
from the sale of oil and gas properties and available borrowings under our
credit facility. At September 30, 2011, we had $8.4 million of availability
under the facility, which included $1.6 million in outstanding letters of
credit. On October 31, 2011, we had $9.9 million of availability under the
facility.
Cash Flows from Operating Activities
Cash flows provided by operating activities decreased $5.8 million from
$35.3 million for the nine months ended September 30, 2010, to $29.5 million for
the nine months ended September 30, 2011. The decrease was primarily due to a
decline in revenues which was only partially offset by our commodity derivative
instruments.
Cash Flows from Investing Activities
Cash flows used in investing activities were $22.4 million for the nine
months ended September 30, 2010, compared to $17.9 million for the nine months
ended September 30, 2011. Capital expenditures were $22.9 million and
$23.4 million for the nine months ended September 30, 2010 and 2011,
respectively. Our purchase of a 14.9% voting interest in CEP in 2011 included
$6.9 million in cash for consideration paid to the seller and for transaction
fees. Cash proceeds from the second and third phases of our Appalachia Basin
sale in 2011 were $10.7 million. Proceeds from the sale of equity securities
received from the Appalachia Basin sale were $1.6 million. The following table
sets forth our capital expenditures, including costs we have incurred but not
paid, by major categories for the nine months ended September 30, 2011 (in
thousands):
Nine Months Ended
September 30, 2011
Capital expenditures
Leasehold acquisition $ 840
Development 20,579
Pipelines 642
Other items 2,450
Total capital expenditures $ 24,511
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