Add
PSTR to Portfolio
Set Alert
Email to a
Friend
| |||
|
|
Quotes & Info
|
| PSTR > SEC Filings for PSTR > Form 10-Q on 8-Aug-2012 | All Recent SEC Filings |
8-Aug-2012
Quarterly Report
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 the first six months of 2012, we recompleted 36 wells, of which 30 were to increase oil production, and drilled three new oil wells. Capital spending during this period included $4.1 million on drilling and recompletions, $1.6 million to complete our vehicle and equipment efficiency projects, $1.2 million to connect two sections of our gathering system to improve production, $296,000 to complete our consolidation and upgrade of facilities in the Cherokee Basin, $100,000 on land, $377,000 on our interstate pipeline and $1.5 million on information technology and other projects. 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. Prices fell below $2.00 per MMbtu in April 2012 and are currently around $3.00 per MMbtu. These depressed prices may not return to levels that encourage dry gas development for some time. As a result, we have curtailed all capital expenditures related to natural gas and have directed our drilling capital to oil development opportunities consisting of recompletions, workovers and new drilling locations on existing leasehold. This change in capital development focus is a significant contributing factor to our 8.2% decline in gas production and 13.2% increase in oil production when comparing the six month periods ending June 30, 2011 and 2012.
Since March 2012, we have performed 30 Cherokee Basin recompletions. The projects are low cost and should not add significant operating costs. It appears the projects have a 50% success rate and, in aggregate including those that prove unsuccessful, a rate of return greater than 75% at current prices. During the quarter, we also drilled three oil wells in southeast Kansas at a combined cost of only $316,000. Production from the three averaged 20 net barrels a day for the first 30 days. We expect to pursue additional such development opportunities in the near future, including ten to twelve workovers a month for the remainder of the year.
Results of Operations
Operating segment data for the periods indicated are as follows (in thousands):
Three Months Ended Six Months Ended
June 30, June 30,
2011 2012 2011 2012
Revenues
Oil and gas sales $ 21,525 $ 10,650 $ 41,762 $ 24,272
Gathering 1,533 474 2,889 1,173
Total production segment 23,058 11,124 44,651 25,445
Pipeline segment 2,466 2,814 5,639 6,242
Total $ 25,524 $ 13,938 $ 50,290 $ 31,687
Operating profit (loss)
Production $ 8,129 $ (6,781 ) $ 21,259 $ (10,019 )
Pipelines 232 1,208 805 2,908
Total segment operating profit (loss) 8,361 (5,573 ) 22,064 (7,111 )
General and administrative expenses (5,148 ) (3,878 ) (10,036 ) (8,457 )
Litigation reserve (100 ) - (9,600 ) -
Total operating profit (loss) $ 3,113 $ (9,451 ) $ 2,428 $ (15,568 )
|
Three Months Ended June 30, 2011 Compared to the Three Months Ended June 30, 2012
The following table presents financial and operating data for the periods indicated as follows:
Three Months Ended
June 30, Increase/
2011 2012 (Decrease)
($ in thousands except per unit data)
Production Segment
Oil and gas sales $ 21,525 $ 10,650 $ (10,875 ) (50.5 )%
Gathering revenue $ 1,533 $ 474 $ (1,059 ) (69.1 )%
Production expense $ 11,406 $ 10,699 $ (707 ) (6.2 )%
Depreciation, depletion and amortization $ 5,955 $ 6,940 $ 985 16.5 %
Gain (loss) on disposal of assets $ 2,432 $ (266 ) $ (2,698 ) (110.9 )%
Production Data
Oil production (Mbbls) 20 24 4 20.0 %
Natural gas production (Mmcfe) 4,624 4,111 (513 ) (11.1 )%
Total production (Mmcfe) 4,742 4,256 (486 ) (10.2 )%
Average daily production (Mmcfe/d) 52.1 46.8 (5.3 ) (10.2 )%
Average Sales Price per Unit (Mcfe)
Natural Gas (Mcf) $ 4.23 $ 2.06 $ (2.17 ) (51.3 )%
Oil(Bbl) $ 99.96 $ 90.13 $ (9.83 ) (9.8 )%
Natural Gas Equivalent (Mcfe) $ 4.54 $ 2.50 $ (2.04 ) (44.9 )%
Average Unit Costs per Mcfe
Production expense $ 2.41 $ 2.51 $ 0.10 4.1 %
Depreciation, depletion and amortization $ 1.26 $ 1.63 $ 0.37 29.4 %
Pipeline Segment
Pipeline revenue $ 2,466 $ 2,814 $ 348 14.1 %
Pipeline expense $ 1,356 $ 765 $ (591 ) (43.6 )%
Depreciation and amortization expense $ 881 $ 841 $ (40 ) (4.5 )%
Gain on disposal of assets $ 3 $ - $ (3 ) * %
|
* Not meaningful
Oil and gas sales decreased $10.9 million, or 50.5%, from $21.5 million during the three months ended June 30, 2011, to $10.6 million during the three months ended June 30, 2012. Lower oil and natural gas prices resulted in decreased revenues of $9.1 million and lower gas production volumes decreased revenue by $2.2 million. These decreases were slightly offset by increased oil revenue of $441,000 resulting from the 20.0% increase in volumes. Our average realized natural gas equivalent prices decreased from $4.54 per Mcfe for the three months ended June 30, 2011, to $2.50 per Mcfe for the three months ended June 30, 2012.
Gathering revenue decreased $1.1 million, or 69.1%, from $1.5 million for the three months ended June 30, 2011, to $474,000 for the three months ended June 30, 2012. The decrease is primarily due to the settlement of the royalty lawsuit which lowered the rates that we receive for gathering royalty interest gas coupled with lower production volumes.
Pipeline revenue increased $348,000, or 14.1%, from $2.5 million for the three months ended June 30, 2011, to $2.8 million for the three months ended June 30, 2012. The increase is a result of higher throughput from growing gas volumes associated with oil production in Osage County, Oklahoma.
Production expense consists of lease operating expenses, production taxes and gathering expense. Production expense decreased $707,000, or 6.2%, from $11.4 million for the three months ended June 30, 2011, to $10.7 million for the three months ended June 30, 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 $691,000 and decreased gathering costs of $470,000. A reduction in production taxes of $702,000 also contributed to the decrease. These decreases were offset by a reduction in ability to capitalize costs of $713,000, increased workover expenses of $319,000 and increased maintenance expenses of $241,000 driven by weather related issues in April 2012. Production expense was $2.41 per Mcfe for the three months ended June 30, 2011, as compared to $2.51 per Mcfe for the three months ended June 30, 2012.
Pipeline expense decreased $591,000, or 43.6%, from $1.3 million during the three months ended June 30, 2011, to $765,000 during the three months ended June 30, 2012. Costs were lower in the current period as the prior year period included $223,000 of costs related to integrity testing and maintenance that is scheduled but has not yet occurred this year as well as $194,000 of costs related to a capacity lease that expired at the end of October 2011.
Depreciation, depletion and amortization increased $945,000, or 13%, from $6.8 million during the three months ended June 30, 2011, to $7.7 million during the three months ended June 30, 2012. Depletion and amortization on our production properties increased approximately $985,000, or 16.5%, from $5.9 million during the three months ended June 30, 2011, to $6.9 million during the three months ended June 30, 2012. On a per unit basis, we had an increase of $0.37 per Mcfe from $1.26 per Mcfe during the three months ended June 30, 2011, to $1.63 per Mcfe during the three months ended June 30, 2012. Increased depletion and amortization was primarily due to a higher depletion rate offset by lower production volumes in the current quarter. Depreciation and amortization expense on our pipeline segment decreased $40,000, or 4.5%, from $881,000 during the three months ended June 30, 2011, to $841,000 during the three months ended June 30, 2012.
General and administrative expenses decreased $1.2 million, or 24.7%, from $5.1 million during the three months ended June 30, 2011, to $3.9 million during the three months ended June 30, 2012. The decrease was primarily due to reduced compensation costs of $900,000 and reduced legal fees of $185,000 compared to the prior year period.
Litigation reserve expense was $100,000 for the three months ended June 30, 2011, with none recorded for the three months ended June 30, 2012. The 2011 expense was recorded to increase the litigation reserve for our Oklahoma royalty lawsuits from $5.5 million to $5.6 million, the amount of the settlement, which was paid in July 2011. A separate royalty owner lawsuit in Kansas 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.
We recorded a gain on disposal of assets of $2.4 million during the three months ended June 30, 2011, compared to a loss of $266,000 during the current year period. The gain in 2011 was primarily due to the third and final phase of the Appalachia Basin sale in June 2011. Gross proceeds from this phase were $4.9 million.
Other income (expense) consists primarily of gains (losses) from derivative instruments, gain (loss) from equity investment, gain on forgiveness of debt and net interest expense. We recorded unrealized losses of $1.1 million and $18.8 million on our derivative contracts for the three months ended June 30, 2011 and 2012, respectively. We recorded realized gains of $6.7 million and $18.6 million on our derivative contracts for the three months ended June 30, 2011 and 2012, respectively. We recorded a mark-to market loss on our equity investment in Constellation Energy Partners LLC ("CEP") of $6.6 million for the three months ended June 30, 2012, with none recorded in the prior year quarter. Gain on forgiveness of debt was $1.6 million and $255,000 for the three months ended June 30, 2011 and 2012, respectively. The gains were a result of the settlement of our QER Loan under a troubled debt restructuring as discussed in Liquidity and Capital Resources below. Interest expense, net, was $2.6 million during the three months ended June 30, 2011, and $2.5 million during the three months ended June 30, 2012. Reduced interest charges as a result of lower debt balances were partially offset by accretion charges to increase the present value of our litigation reserve.
Six Months Ended June 30, 2011 Compared to the Six Months Ended June 30, 2012
The following table presents financial and operating data for the periods
indicated as follows:
Six Months Ended
June 30, Increase/
2011 2012 (Decrease)
($ in thousands except per unit data)
Production Segment
Oil and gas sales $ 41,762 $ 24,272 $ (17,490 ) (41.9 )%
Gathering revenue $ 2,889 $ 1,173 $ (1,716 ) (59.4 )%
Production expense $ 23,840 $ 22,200 $ (1,640 ) (6.9 )%
Depreciation, depletion and amortization $ 11,906 $ 13,102 $ 1,196 10.0 %
Gain (loss) on disposal of assets $ 12,354 $ (162 ) $ (12,516 ) (101.3 )%
Production Data
Oil production (Mbbls) 38 43 5 13.2 %
Natural gas production (Mmcfe) 9,186 8,429 (757 ) (8.2 )%
Total production (Mmcfe) 9,415 8,685 (730 ) (7.7 )%
Average daily production (Mmcfe/d) 52.0 47.7 (4.3 ) (8.3 )%
Average Sales Price per Unit (Mcfe)
Natural Gas (Mcf) $ 4.15 $ 2.40 $ (1.75 ) (42.2 )%
Oil(Bbl) $ 94.37 $ 94.10 $ (0.27 ) (0.3 )%
Natural Gas Equivalent (Mcfe) $ 4.44 $ 2.79 $ (1.65 ) (37.2 )%
Average Unit Costs per Mcfe
Production expense $ 2.53 $ 2.56 $ 0.03 1.1 %
Depreciation, depletion and amortization $ 1.26 $ 1.51 $ 0.25 19.8 %
Pipeline Segment
Pipeline revenue $ 5,639 $ 6,242 $ 603 10.7 %
Pipeline expense $ 3,016 $ 1,647 $ (1,369 ) (45.4 )%
Depreciation and amortization expense $ 1,821 $ 1,692 $ (129 ) (7.1 )%
Gain on disposal of assets $ 3 $ 5 $ 2 66.7 %
|
Oil and gas sales decreased $17.5 million, or 41.9%, from $41.8 million during the six months ended June 30, 2011, to $24.3 million during the six months ended June 30, 2012. Lower natural gas prices resulted in decreased revenues of $14.8 million and lower gas production volumes decreased revenue by $3.1 million. These decreases were slightly offset by increased oil revenue of $423,000 resulting primarily from the 13.2% increase in production volume. Our average realized natural gas equivalent prices decreased from $4.44 per Mcfe for the six months ended June 30, 2011, to $2.79 per Mcfe for the six months ended June 30, 2012.
Gathering revenue decreased $1.7 million, or 59.4%, from $2.9 million for the six months ended June 30, 2011, to $1.2 million for the six months ended June 30, 2012. The decrease is primarily due to the settlement of the royalty lawsuit which lowered the rates that we receive for gathering royalty interest gas coupled with lower production volumes.
Pipeline revenue increased $603,000, or 10.7%, from $5.6 million for the six months ended June 30, 2011, to $6.2 million for the six months ended June 30, 2012. The increase is the result of gas being produced in Osage County, Oklahoma, in connection with oil drilling activity in the area.
Production expense decreased $1.6 million, or 6.9%, from $23.8 million for the six months ended June 30, 2011, to $22.2 million for the six months ended June 30, 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 $1.4 million and decreased gathering costs of $705,000. Also contributing to the decrease was a reduction in production taxes of $1.6 million primarily due to lower gas prices and production. These reductions were offset by decreased capitalized expenses of $1.3 million due to reduced drilling activity, a one-time charge of $368,000 related to our March 2012 field reorganization, increased maintenance expenses of $214,000 and a $247,000 increase across various other expense items. Production expense was $2.53 per Mcfe for the six months ended June 30, 2011, as compared to $2.56 per Mcfe for the six months ended June 30, 2012. Excluding the field reorganization charge, production expense was $2.51 per Mcfe for the six months ended June 30, 2012.
Pipeline expense decreased $1.4 million, or 45.4%, from $3.0 million during the six months ended June 30, 2011, to $1.6 million during the six months ended June 30, 2012. Costs were lower in the current period as the prior year period included $254,000 of costs related to integrity testing and maintenance that is scheduled but has not yet occurred this year, $455,000 of costs related to a capacity lease that expired at the end of October 2011 and $335,000 of costs from an external gas leak that occurred during the first quarter of 2011.
Depreciation, depletion and amortization increased $1.1 million, or 7.8%, from $13.7 million during the six months ended June 30, 2011, to $14.8 million during the six months ended June 30, 2012. Depletion and amortization on our production properties increased approximately $1.2 million, or 10%, from $11.9 million during the six months ended June 30, 2011, to $13.1 million during the six months ended June 30, 2012. On a per unit basis, we had an increase of $0.25 per Mcfe from $1.26 per Mcfe during the six months ended June 30, 2011, to $1.51 per Mcfe during the six months ended June 30, 2012. Increased depletion and amortization was primarily due to a higher depletion rate offset by lower production volumes in the current quarter. Depreciation and amortization expense on our pipeline segment decreased $129,000, or 7.1%, from $1.8 million during the six months ended June 30, 2011, to $1.7 million during the six months ended June 30, 2012.
General and administrative expenses decreased $1.6 million, or 15.7%, from $10.0 million during the six months ended June 30, 2011, to $8.4 million during the six months ended June 30, 2012. The cost reduction is primarily due to lower wages, bonuses and benefits during the current year of $714,000 partially offset by higher contract labor of $183,000. Additionally, all material lawsuits were settled in 2011 driving a reduction in our legal costs of $644,000 and a workman's compensation payout of $310,000 that was recognized in the 2011 period with no payout in 2012.
Litigation reserve expense was $9.6 million for the six months ended June 30, 2011, with none recorded for the six months ended June 30, 2012. The expense in 2011 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. As discussed above, these lawsuits were settled in 2011.
We recorded a gain on disposal of assets of $12.4 million during the six months ended June 30, 2011, compared to a loss of $157,000 during the current year period. The gain in 2011 was primarily due to the second and third phases of the Appalachia Basin sale. Gross proceeds from both phases were $16.6 million.
Other income (expense) consists primarily of gains (losses) from derivative instruments, gain (loss) from equity investment, gain on forgiveness of debt and net interest expense. We recorded unrealized losses of $11.2 million and $18.8 million on our derivative contracts for the six months ended June 30, 2011 and 2012, respectively. We recorded realized gains of $15.9 million and $30.7 million on our derivative contracts for the six months ended June 30, 2011 and 2012, respectively. We recorded a mark-to market loss on our equity investment CEP of $2.5 million for the six months ended June 30, 2012 with none recorded in the prior year. Gain on forgiveness of debt was $1.6 million and $255,000 for the six months ended June 30, 2011 and 2012, respectively. The gains were a result of the settlement of our QER Loan under a troubled debt restructuring. Interest expense, net, was $5.3 million during the six months ended June 30, 2011, and $5.2 million during the six months ended June 30, 2012. Reduced interest charges as a result of lower debt balances were partially offset by accretion charges to increase the present value of our litigation reserve.
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 received 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 six months ended June 30, 2012, were cash generated from our hedging activities, the sale of common stock to White Deer Energy L.P. and its affiliates ("White Deer"), cash flows from operations and borrowings under our borrowing base credit facility. We also generated $1.3 million of cash from the release of escrowed proceeds from our Appalachia Basin sale. At June 30, 2012, we had decreased our debt by $25.6 million from December 31, 2011.
Cash Flows from Operating Activities
Cash flows provided by operating activities increased $5.2 million from $21.5 million for the six months ended June 30, 2011, to $26.7 million for the six months ended June 30, 2012. The increase was driven by an increase in cash settlements of our derivative contracts in part due to the repricing of July and August 2012 hedges during the current quarter, lower operating expenses and a reduction in working capital. Increases to cash flow from operating activities were partially offset by a reduction in oil and gas revenues.
Cash Flows from Investing Activities
Cash flows used in investing activities were $4.6 million for the six months ended June 30, 2011, compared to $8.7 million for the six months ended June 30, 2012. Capital expenditures were $15.3 million and $9.0 million for the six months ended June 30, 2011 and 2012, respectively. We received proceeds from the sale of assets of $10.7 million and $293,000 for six months ended June 30, 2011 and 2012, respectively. Proceeds from the sale of assets in 2011 were primarily from the second and third phases of our Appalachia Basin asset sale. Capital expenditures are lower in the current year period compared to the prior year as we have curtailed spending on natural gas projects in response to depressed prices. The following table sets forth our capital expenditures, including costs we have incurred but not paid, by major categories for the six months ended June 30, 2012 (in thousands):
Six
Months Ended
June 30, 2012
Capital expenditures
Leasehold acquisition $ 100
Development 5,317
Pipelines 377
Other items 3,414
Total capital expenditures $ 9,208
|
Cash Flows from Financing Activities
Cash flows used in financing activities were $16.3 million for the six months ended June 30, 2011, as compared to $18.2 million for the six months ended June 30, 2012. Debt repayments were $16.3 million and $25.6 million for the six months ended June 30, 2011 and 2012, respectively. During February 2012, we issued $7.5 million of common stock to White Deer. Proceeds from this issuance were offset by $76,000 of equity issuance costs.
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 for debt repayment and other general corporate purposes.
At August 2, 2012, after application of the proceeds from the White Deer investment described below, we had cash on hand of $270,000, borrowings of $157.9 million and $1.4 million in outstanding letters of credit. With a borrowing base of $166.5 million, we had $7.2 million available under our . . .
|
|