Gastar Touts Deep Bossier Well Completions - 4Q Report

Gastar Exploration reported operating results for the three months and twelve months ended December 31, 2009.

Highlights for 2009 include:

  • The year ended with $21.9 million in cash and short term bank debt of $17 million which was repaid in full in early January 2010;
  • Deep Bossier wells completed late December 2008 and mid-year 2009 were the Company's best to date, with an average initial production (IP) rate of 25 million cubic feet of natural gas per day;
  • First vertical Marcellus test confirmed significant shale potential under a portion of our acreage; and
  • 2010 was entered with limited interest expense, control of operations and capital outlays, and an expanded drilling program.

Fourth Quarter Operating Results

Natural gas and oil revenues, after the impact of realized hedging activity, decreased 33% to $7.7 million in the fourth quarter of 2009 from $11.5 million in the fourth quarter of 2008. This decrease was due to a 31% decline in realized natural gas prices and a 4% decline in production volumes, primarily in Wyoming.

Average daily production for the fourth quarter of 2009 was 23.0 million cubic feet of natural gas equivalents per day, compared to 23.9 MMcfe for the fourth quarter of 2008 and 23.3 MMcfe for the third quarter of 2009. In East Texas, average daily production increased 11% to 20.1 MMcfe, while volumes in Wyoming declined 55% to 2.5 MMcfe per day compared to the fourth quarter of 2008. Compared to third quarter 2009, overall production was down 1% as a result of East Texas production remaining relatively flat due to recompletion activity while Wyoming production declined approximately 300 MMcfe per day.

During the three months ended December 31, 2009, approximately 90% of our natural gas production had NYMEX price protection. The net realized effect of this hedging program was an increase of $219,000 in revenues, reflecting an increase in total price received from $3.50 per Mcf to $3.60 per thousand cubic feet. The positive benefit of the NYMEX hedging program of $1.3 million or $0.60 per Mcf was negatively impacted by area basis hedge losses of $1.1 million or $0.50 per Mcf. The realized effect of hedging in the fourth quarter of 2008 was an increase of $1.0 million in revenues, reflecting an increase in total price received from $4.77 per Mcf to $5.23 per Mcf. The unrealized non-cash effect of our hedging program was a gain of $145,000 for the fourth quarter of 2009 and a gain of $5.0 million for the fourth quarter of 2008.

Lease operating expense (LOE) was $1.5 million in the fourth quarter of 2009, compared to $1.7 million in the fourth quarter of 2008 and $1.8 million in the third quarter of 2009. LOE per Mcfe decreased 9% to $0.70 in the fourth quarter of 2009, compared to $0.77 per Mcfe during the fourth quarter of 2008 and decreased 15% compared to $0.82 in the third quarter of 2009. Excluding workover, insurance, property tax, and certain non-recurring costs or benefits, our direct lease operating expenses were $0.47 per Mcfe for the fourth quarter of 2009 compared to $0.60 per Mcfe for the same period in 2008 and $0.58 for the third quarter of 2009. Depletion, depreciation and amortization (DD&A) was $2.2 million in the fourth quarter of 2009, compared to $6.1 million in the fourth quarter of 2008 and $3.0 million in the third quarter of 2009. The decrease in the rate per Mcfe was due to lower depletable costs following a $68.7 million impairment charge taken in the first quarter of 2009 and the sale of our interest in the Hilltop Resort Gathering System in November 2009 with net proceeds of $21.8 million credited to the full cost pool.

Year-End Reserves

Total proved reserves as of December 31, 2009 were 48.5 billion cubic feet of natural gas and 66,700 barrels of oil, or 48.9 billion cubic feet of natural gas equivalent, of which 73% were proved developed reserves. The present value of estimated future cash flows, discounted at 10% per year (PV-10"), was $45.6 million as of December 31, 2009, utilizing the new U.S. Securities and Exchange Commission Henry Hub 12-month unweighted average of the first-day-of-the-month pricing methodology of $3.87 per million British thermal units, Katy Hub price of $3.68 per MMBtu, and CIG price of $3.04 per MMBtu and an oil price of $57.65 per barrel. Total proved reserves as of December 31, 2008 were 63.7 Bcf of natural gas and 12,000 barrels of oil, or 63.8 Bcfe, of which 63% was proved developed reserves. The PV-10 value was $110.1 million as of December 31, 2008 using a flat case price of $4.56 per MMBtu, which was based on the old SEC pricing methodology of applying prices at year-end.

The 2009 downward revision of previous estimates of natural gas reserves is primarily attributable to lower natural gas prices as calculated under the new SEC pricing methodology. Natural gas prices utilizing the new SEC price methodology decreased approximately 35% from December 31, 2008 to December 31, 2009, resulting in a decrease in proved reserves of approximately 11,300 MMcf. The negative impact from natural gas prices was partially offset by upward performance revisions, primarily in the Hilltop area of East Texas.

For comparative purposes, in addition to the new SEC pricing methodology, our independent petroleum consultant also prepared estimates of our year-end proved reserves using two alternative commodity price assumptions. Under the old pricing methodology which would have utilized December 31, 2009 Henry Hub spot market price of $5.79 per MMBtu, Katy Hub price of $5.72 per MMBtu, and CIG price of $5.54 per MMBtu for natural gas and an oil price of $76.00 per barrel, our reserves at the end of 2009 would have been 60.3 Bcfe, with a PV-10 value of $112.7 million. They also performed a comparison to a NYMEX case based on the forward closing prices on the New York Mercantile Exchange for natural gas and oil as of December 31, 2009. For gas volumes the price increased from $5.79 to $8.51 per MMBtu and the oil price increased from $81.95 to $98.50 per barrel over the life of the properties. In the NYMEX case, proved reserves were 68.7 Bcfe, with a PV-10 value of $133.6 million.

J. Russell Porter, Gastar's President and Chief Executive Officer, commented, "Although our reserves under the new SEC-prescribed calculation method were lower at year-end 2009 than in 2008, if you compare results using the same methodology used in 2008, reserves declined by only 5.5%. Considering our limited 2009 drilling capital budget and related Texas drilling activity reduction, we are satisfied with these results and look forward to a more active and productive 2010."

Operations Review and Update

In East Texas, net production for the fourth quarter of 2009 from the Hilltop area averaged 20.1 MMcfe per day, flat with the 20.0 MMcfe per day in the third quarter of 2009, but up from 18.1 MMcfe per day in the fourth quarter of 2008. The 11% year-over-year increase in volumes is due to incremental production from two wells completed in 2009 and full year production from the Belin #1, five wells recompleted in additional zones and one workover operation conducted over the 12-month period. Although no additional wells were brought on production in the fourth quarter, the natural decline in production was offset by an active recompletion program. During the quarter, 5 zones were recompleted in three wells to bring production on from existing behind pipe nonproducing zones.

Capital expenditures for the fourth quarter of 2009 in East Texas were $5.0 million, which primarily related to drilling the Donelson #4 well and various recompletion activities. We spudded the Donelson #4, an approximate 19,000-foot lower Bossier test, in late October; however, as previously announced, due to hole stability problems, the well is undergoing second sidetrack operations. The well is expected to take approximately six to eight weeks longer to reach total depth and require approximately gross $4.0 (net $2.7) million in additional drilling costs to reach total depth. We anticipate a portion of these costs to be reimbursed under our well control insurance policy. We remain very encouraged about its ultimate success. The Donelson #4 is an offset to the highly prolific Belin #1 and Donelson #3 wells. We have obtained log information that confirms the presence of the target sands, and we have encountered several strong drilling breaks and gas shows in the targeted lower Bossier formations while drilling.

In 2010, we are planning three additional lower Bossier exploratory wells, one horizontal well to test an Eagle Ford equivalent zone and up to 5 recompletions in two existing wells in East Texas. Due to the delay in the Donelson #4 well we anticipate first quarter net production to be 17 to 19 MMcfe per day resulting in total company net production of 20 to 21 MMcfe per day.

As previously reported, we sold our majority interest in the Hilltop Resort Gathering System in November 2009 and received net proceeds of approximately $21.8 million, which was credited to the full cost pool and thus no gain was recognized on the transaction. The agreement involves current fees of $0.325 per Mcf and requires a minimum of 50 MMcf per day of gross production. Due to delays in the Donelson #4 drilling the minimum production threshold will not be met resulting in a make-up payment of approximately of $300,000 being due in the first quarter of 2010.

In Appalachia, we drilled our first vertical Marcellus Shale well in the fourth quarter of 2009, the James Yoho #1. The well encountered approximately 46 feet of Marcellus Shale, was completed with a single stage frac and tested at a stabilized gross rate of 1.5 MMcf per day and 120 barrels of condensate per day with no water production. We believe this test confirms that thinner portions of the Marcellus Shale are capable of generating excellent production rates. Currently, we do not expect sales from the Yoho # 1 until late in the third quarter of 2010 when pipeline to the well should be completed.

We have a total of 15 shallow vertical wells on our approximately 36,000 net acres in northern West Virginia and southwestern Pennsylvania, of which 11 are on production, and the remaining wells are scheduled to be on production in the next 90 days. For the three months ended December 31, 2009, net production from the Appalachia area averaged approximately 0.4 MMcfe per day. We plan to continue to conduct this shallow well drilling program to hold certain leases by production.

For 2010, we expect to drill 4 gross (2.1 net) horizontal and 2 gross (2 net) vertical Marcellus Shale wells and 7 additional shallow Devonian wells. The next well -- most likely a horizontal well -- is targeted to spud late in the second quarter.



 

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