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| GST > SEC Filings for GST > Form 10-Q on 7-Nov-2012 | All Recent SEC Filings |
7-Nov-2012
Quarterly Report
Overview
We are an independent energy company engaged in the exploration, development and
production of natural gas and oil in the U.S. Our principal business activities
include the identification, acquisition, and subsequent exploration and
development of natural gas and oil properties with an emphasis on unconventional
natural gas reserves, such as shale resource plays. We are currently pursuing
the development of liquids-rich natural gas in the Marcellus Shale play in the
Appalachia area of West Virginia and central and southwestern Pennsylvania. We
also hold prospective acreage in the deep Bossier gas play in the Hilltop area
of East Texas and in the Mid-Continent area of the U.S.
Parent is a Canadian corporation, incorporated in Alberta in 1987 and subsisting
under the Business Corporations Act (Alberta), with its common shares listed on
the NYSE MKT under the symbol "GST." Parent is a holding company. Substantially
all of the Company's operations are conducted through, and substantially all of
its assets are held by, Parent's primary operating subsidiary, Gastar USA, and
its subsidiaries. Gastar USA's Series A Preferred Stock is listed on the NYSE
MKT under the symbol "GST.PRA."
Our current operational activities are conducted primarily in the U.S. As of
September 30, 2012, our major assets consist of approximately 108,300 gross
(75,500 net) acres in the Marcellus Shale in West Virginia and southwestern
Pennsylvania, approximately 33,500 gross (17,100 net) acres in the Bossier play
in the Hilltop area of East Texas and approximately 30,900 gross (12,500 net)
acres in the Mid-Continent area of the U.S.
The following discussion addresses material changes in our results of operations
for the three and nine months ended September 30, 2012 compared to the three and
nine months ended September 30, 2011 and material changes in our financial
condition since December 31, 2011. This discussion should be read in conjunction
with our condensed consolidated financial
statements and the notes thereto included in Part I. Item 1. "Financial
Statements" of this report, as well as our 2011 Form 10-K, which includes
important disclosures regarding our critical accounting policies as part of
"Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations." Except as otherwise noted, there are no material differences
between the consolidated information for the Company presented herein and the
consolidated information of Gastar USA.
Natural Gas and Oil Activities
The following provides an overview of our major natural gas and oil projects.
While actively pursuing specific exploration and development activities in each
of the following areas, there is no assurance that new drilling opportunities
will be identified or that any new drilling opportunities will be successful if
drilled.
Marcellus Shale and Other Appalachia. The Marcellus Shale is Devonian aged shale
that underlies much of the Appalachian region of Pennsylvania, New York, Ohio,
West Virginia and adjacent states. The depth of the Marcellus Shale and its low
permeability make the Marcellus Shale an unconventional exploration target in
the Appalachian Basin. Advancements in horizontal drilling and stimulation have
produced promising results in the Marcellus Shale. These developments have
resulted in increased leasing and drilling activity in the area. As of
September 30, 2012, our acreage position in the play was approximately 108,300
gross (75,500 net) acres. We refer to the approximately 47,100 gross (21,000
net) acres reflecting our interest in our Marcellus Shale assets in West
Virginia and Pennsylvania subject to the Atinum Joint Venture described below as
our Marcellus West acreage. We refer to the approximately 61,200 gross (54,400
net) acres in Preston, Tucker, Pocahontas, Randolph and Pendleton Counties, West
Virginia as our Marcellus East acreage. The entirety of our acreage is believed
to be in the core, over-pressured area of the Marcellus play.
On September 21, 2010, we entered into the Atinum Joint Venture pursuant to a
purchase and sale agreement with Atinum. Pursuant to the agreement, at the
closing of the transaction on November 1, 2010, we assigned to Atinum, for $70.0
million in total consideration, an initial 21.43% interest in all of our
existing Marcellus Shale assets in West Virginia and Pennsylvania, consisting of
certain undeveloped acreage and a 50% working interest in 16 producing shallow
conventional wells and one non-producing vertical Marcellus Shale well (the
"Atinum Joint Venture Assets"). Atinum paid us approximately $30.0 million in
cash upon closing. Additionally, Atinum was obligated to fund its 50% share of
drilling, completion and infrastructure costs, and paid an additional $40.0
million of drilling costs in the form of a drilling carry obligation by funding
75% of our 50% share of those same costs. Upon completion of the funding of the
drilling carry, we made additional assignments in early 2012, as necessary, to
Atinum as a result of which Atinum now owns a 50% interest in the Atinum Joint
Venture Assets.
The Atinum Joint Venture's initial three-year development program called for the
partners to drill a minimum of 12 horizontal wells in 2011 and 24 horizontal
wells in each of 2012 and 2013. Due to recent natural gas price declines, Atinum
and Gastar USA initially agreed to reduce the 2012 minimum wells to be drilled
requirement from 24 wells to 20 wells. Atinum and Gastar USA subsequently agreed
to extend the rig contract to May 2013 in the Marcellus Shale resulting in a
plan to drill and complete approximately 26 gross (12.7 net) wells during 2012.
During the nine months ended September 30, 2012, we drilled and cased 16 gross
(7.7 net) operated wells, completed fracture stimulation operations on 17 gross
(8.0 net) operated wells and were in the process of fracture stimulating five
gross (2.2 net) operated wells in Marshall County, West Virginia. We were also
in various stages of drilling on 12 gross (6.0 net) operated wells in Marshall
County, West Virginia. All of our 2012 Marcellus Shale well operations were
under the Atinum Joint Venture. Effective June 30, 2011, Atinum has the right to
participate in any future leasehold acquisitions made by us within Ohio, New
York, Pennsylvania and West Virginia, excluding the counties of Pendleton,
Pocahontas, Preston, Randolph and Tucker, West Virginia, on terms identical to
those governing the existing Atinum Joint Venture. We will act as operator and
are obligated to offer any future lease acquisitions to Atinum on a 50/50 basis.
Atinum will pay us on an annual basis an amount equal to 10% of lease bonuses
and third party leasing costs up to $20.0 million and 5% of such costs on
activities above $20.0 million.
In December 2010, we completed a Marcellus Shale leasehold acquisition for the
Marcellus East acreage for an aggregate purchase price of $28.9 million. The
acquisition consisted of undeveloped leasehold in the Marcellus Shale
concentrated in Preston, Tucker, Pocahontas, Randolph and Pendleton Counties,
West Virginia, including a gathering system comprised of 41 miles of four and
six inch steel pipeline, a salt water disposal well, and five conventional
producing wells. The Marcellus East acreage was outside the initial AMI with
Atinum, and Atinum elected not to acquire a 50% interest as provided under the
terms of the Atinum Joint Venture. We believe their decision was due to the
timing of the transaction and limited prior operational results within the
initial Atinum Joint Venture AMI. We have completed the drilling of the Hickory
Ridge 2H horizontal Marcellus well in Marcellus East in Preston County, West
Virginia. We completed the 2,500 foot lateral with a ten-stage fracture
stimulation in August 2011 and to date, the well has recovered approximately 59%
of the fluids used in its completion. Nearby vertical wells experienced low gas
rates prior to recovering at least 75% of completion fluids. Due to low natural
gas prices and in an effort to reduce operating costs, we are installing a pump
jack to assist with accelerating the recovery of the completion fluids from the
well. Due to the current natural gas price environment, we are currently not
planning to drill any additional wells on the Marcellus East acreage during
2012.
As of September 30, 2012, our operated wells capable of production in Marshall County, West Virginia were comprised of the following:
Average
Net Lateral
Gross Well Revenue Length (in
Pad Count Net Well Count Working Interest Interest feet) (1) Status
Corley 4.0 1.6 40.8% 35.4% 4,900 Producing
Simms 3.0 1.5 50.0% 43.2% 5,000 Producing
Hall 3.0 1.2 40.0% 34.7% 4,400 Producing
Hendrickson 5.0 2.0 40.0% 34.7% 4,700 Producing
Accettolo 3.0 1.5 50.0% 40.2% 4,600 Producing
Burch Ridge 5.0 2.5 50.0% 41.5% 5,800 Producing
Wayne 4.0 2.0 50.0% 40.6% 5,700 Producing
Wengerd 2.0 0.9 44.5% 37.7% 5,200 Shut-in (2)
29.0 13.2
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(2) The Wengerd 1H and 7H wells were shut-in to accommodate the current drilling of five additional Wengerd horizontal wells on the pad, discussed in further detail below. We anticipate that these wells will be returned to production during December 2012 when the five additional Wengerd wells are turned to production.
As of September 30, 2012, we had drilling operations at various stages on the following wells in Marshall County, West Virginia:
Average
Estimated Lateral
Gross Net Net Length Estimated
Well Well Working Revenue (in feet) Production
Pad Count Count Interest Interest (1) Status Date
Awaiting fracture Early
Wengerd 5.0 2.2 44.5% 37.7% 5,000 stimulation/completion December
2012
One drilled to total Late
Lily 4.0 2.0 50.0% 40.6% 5,100 depth; three drilled December
to kick off point 2012
Eight drilled to kick First and
Shields 9.0 4.5 50.0% 42.0% 2,800 off point; one drilled Third
to intermediate casing Quarters
point 2013
18.0 8.7
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Currently, we have the following drilling operations in Marshall County, West
Virginia:
Average
Estimated Lateral
Gross Net Net Length Estimated
Well Well Working Revenue (in feet) Production
Pad Count Count Interest Interest (1) Status Date
Fracture stimulation Early
Wengerd 5.0 2.2 44.5% 37.7% 5,000 completed; completion December
operations in progress 2012
Fracture Late
Lily 4.0 2.0 50.0% 40.6% 5,100 stimulation/completion December
operations to begin 2012
mid-November 2012
Currently drilling Second
Addison 5.0 2.5 50.0% 41.7% 5,000 top-holes Quarter
2013
Eight drilled to kick First and
Shields 10.0 5.0 50.0% 42.0% 2,800 off point; one drilled Third
to intermediate casing Quarters
point 2013
24.0 11.7
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As of September 30, 2012, we had participated on a non-operated basis in the
drilling of seven horizontal Marcellus Shale wells in Butler County,
Pennsylvania and an additional four non-operated horizontal Marcellus Shale
wells in Marshall County, West Virginia. Three of the seven Butler County wells
were turned to production on December 1, 2011 with the remaining four wells
completed and turned to sales in March 2012. Our average working interest in the
Butler County non-operated wells is 19.2% (net revenue interest 15.9%) and the
average lateral length of the wells is 3,900 feet. Of the four Marshall County
non-operated wells, two of the wells were on production prior to December 31,
2011 and the remaining wells were placed on production by mid-April 2012. Our
current average working interest in the Marshall County non-operated wells is
21.4% (net revenue interest 18.6%) and the average well lateral length is
approximately 4,200 feet. Currently, we do not plan to participate in any
additional non-operated wells for the remainder of 2012 and 2013.
For the three and nine months ended September 30, 2012, net production from the
Marcellus Shale averaged approximately 23.3 MMcfe/d and 19.4 MMcfe/d,
respectively, compared to 2.9 MMcfe/d and 1.4 MMcfe/d for the three and nine
months ended September 30, 2011, respectively. During the last several quarters,
our operated production and sales in West Virginia have been curtailed by issues
with condensate handling, dehydration limitations, high line pressures and
excessive unscheduled system down-time on a third-party-operated gathering
system. The gathering system operator has been gradually resolving these issues
and certain issues were resolved by late May 2012 by increasing dehydration
capacity to 70 MMcf/d from 40 MMcf/d and adding compression to reduce line
pressure to approximately 550 psi at the Corley CRP. An additional CRP is to be
constructed at the Burch Ridge pad and will have 75 MMcf/d dehydration capacity
and compression to ensure line pressures are maintained at approximately 550
psi. The third-party gathering system was down approximately 18.5% of the days
in the third quarter of 2012 due to a fire at the facility in August 2012 and
downstream NGLs processing plant curtailment in September 2012. The Burch Ridge
CRP is currently scheduled to be operational by early December 2012 which should
further reduce line pressure and limitations to dehydration capacity. If the
Burch Ridge CRP is delayed, we may have to restrict our production in the fourth
quarter of 2012 as the Wengerd pad is placed on production.
Hilltop Area, East Texas. At September 30, 2012, we held leases covering
approximately 33,500 gross (17,100 net) acres in the Bossier play in the Hilltop
area of East Texas in Leon and Robertson Counties. Wells in this area target
multiple potentially productive natural gas formations and are typically
characterized by high initial production and attractive long-lived per well
reserves. Due to current low natural gas prices, we have suspended all Bossier
drilling activities in the Hilltop area for 2012. We are monitoring offset
horizontal drilling activity in the Eagle Ford and Woodbine formations by Encana
Corporation, EOG Resources, Inc. and other companies. Should the drilling
results of the offset operators warrant such, we may consider drilling an Eagle
Ford or Woodbine test well in 2013.
For the three and nine months ended September 30, 2012, net production from the
Hilltop area averaged approximately 14.6 MMcfe/d and 14.1 MMcfe/d, respectively,
compared to 16.6 MMcfe/d and 17.9 MMcfe/d for the three and nine months ended
September 30, 2011, respectively. The decrease in production is the result of
natural field decline and the suspension of our East Texas drilling plans as a
result of low natural gas prices. However, third quarter 2012 net production
benefited by
approximately 1.4 MMcfe/d primarily due to an increase in our Belin #1 net revenue interest based on an updated division order title opinion. Mid-Continent Horizontal Oil Play. At September 30, 2012, we held leases covering approximately 30,900 gross (12,500 net) acres in the previously announced non-operated Mid-Continent horizontal oil play. Our leasing activities are continuing in the initial AMI prospect area and have been expanded to include two additional adjacent prospect areas with a current goal of leasing at least 50,000 combined gross acres within the three prospect areas. For the first 12,500 gross acres acquired in the initial AMI prospect, we paid 62.5% of lease acquisition costs for a 50% leasehold interest and 50% of lease acquisition costs on additional acres in excess of 12,500 gross acres acquired for a 50% working interest. We will pay 54.25% of the lease acquisition costs in the two new prospect areas for a 50% working interest. In each prospect area, we pay 62.5% of the first four wells' gross drilling and completion costs and 56.25 % of the next four wells' gross drilling and completion costs to earn a 50% working interest. For all additional wells beyond the first eight in a prospect area, we are responsible for paying only the drilling and completion costs associated with our 50% working interest (approximate net revenue interest 39.0%). We are responsible for all leasing and permitting activities. In late July 2012, drilling operations commenced on the first of three wells to be drilled during 2012 on the initial prospect area. The first well has a horizontal lateral of approximately 4,200 feet and fracture stimulation operations were completed in late September 2012. Costs to drill and complete the first well are $4.4 million gross ($2.8 million net). Well flow back operations commenced on October 5, 2012 and the well continues to unload completion fluids with approximately 8% of frac fluid flowed back to date. Oil and natural gas production rates continue to increase. The operator plans to drill out the plugs between completion stages by mid-November 2012. The current oil and natural gas production is being sent to sales. Drilling operations on the second well are anticipated to commence by late November 2012 and the third well late in the fourth quarter 2012 on the initial prospect area. The two wells are scheduled to be on production in January and February 2013, respectively. Coalbed Methane - Powder River Basin, Wyoming and Montana. On May 3, 2012, we assigned our working interest in the Powder River Basin to the operator effective January 1, 2012.
Gastar USA Series A Preferred Stock
During the nine months ended September 30, 2012, Gastar USA sold 2,582,407
shares of Series A Preferred Stock under the ATM Agreement for net proceeds of
$49.2 million, resulting in 3,946,950 total shares issued for net proceeds of
$76.6 million at September 30, 2012. From October 1, 2012 to November 5, 2012,
we sold an additional 4,304 shares of Series A Preferred Stock under the ATM
Agreement for net proceeds of $84,000. We plan to continue issuing Series A
Preferred Stock under the ATM Agreement in the future depending on market
conditions and our capital expenditures program. See "Liquidity and Capital
Resources" of this report.
Results of Operations
The following is a comparative discussion of the results of operations for the
periods indicated. It should be read in conjunction with the condensed
consolidated financial statements and the related notes to the condensed
consolidated financial statements found elsewhere in this report.
The following table provides information about production volumes, average prices of natural gas and oil and operating expenses for the periods indicated:
For the Three Months Ended For the Nine Months Ended
September 30, September 30,
2012 2011 2012 2011
Production:
Natural gas (MMcf) 2,783 1,837 7,584 5,437
Oil (MBbl) 42 10 106 31
NGLs (MBbl) 77 5 186 5
Total production (MMcfe) 3,493 1,921 9,339 5,649
Total (Mmcfe/d) 38.0 20.9 34.1 20.7
Average sales price per unit:
Natural gas per Mcf, excluding impact $ 2.27 $ 3.37 $ 1.99 $ 3.41
of realized hedging activities
Natural gas per Mcf, including impact 3.20 4.69 2.97 4.63
of realized hedging activities
Oil per Bbl, excluding impact of 76.54 77.64 68.93 87.91
realized hedging activities
Oil per Bbl, including impact of 83.05 77.64 72.93 87.91
realized hedging activities
NGLs per Bbl, excluding impact of 25.26 52.93 29.02 52.93
realized hedging activities
NGLs per Bbl, including impact of 32.40 52.93 34.31 52.93
realized hedging activities
Average sales price per Mcfe,
excluding impact of realized hedging $ 3.28 $ 3.73 $ 2.98 $ 3.80
activities
Average sales price per Mcfe,
including impact of realized hedging 4.25 4.99 3.92 4.98
activities
Selected operating expenses (in
thousands):
Production taxes $ 560 $ 157 $ 1,494 $ 384
Lease operating expenses 780 2,363 4,754 5,945
Transportation, treating and gathering 1,305 1,128 3,715 3,354
Depreciation, depletion and
amortization 7,135 3,694 19,744 10,797
Impairment of natural gas and oil
properties 78,054 - 150,787 -
General and administrative expense 2,951 3,100 9,263 8,576
Selected operating expenses per Mcfe:
Production taxes $ 0.16 $ 0.08 $ 0.16 $ 0.07
Lease operating expenses 0.22 1.23 0.51 1.05
Transportation, treating and gathering 0.37 0.59 0.40 0.59
Depreciation, depletion and
amortization 2.04 1.92 2.11 1.91
General and administrative expense 0.84 1.61 0.99 1.52
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Three Months Ended September 30, 2012 compared to the Three Months Ended
September 30, 2011
Revenues. Total natural gas, oil and NGLs revenues were $14.8 million for the
three months ended September 30, 2012, up from $9.6 million for the three months
ended September 30, 2011. The increase in revenues was the result of an 82%
increase in production offset by a 15% decrease in weighted average realized
prices. Average daily production on an equivalent basis was 38.0 MMcfe/d for the
three months ended September 30, 2012 compared to 20.9 MMcfe/d for the same
period in 2011. Oil and NGLs production represented approximately 20% of total
production for the three months ended September 30, 2012 compared to 19% and 16%
of total production for the three months ended June 30, 2012 and March 31, 2012,
respectively, and
4% of total production for the prior year three month period, primarily as a result of our increased focus on drilling liquids-rich acreage in 2012. Liquids revenues (oil, condensate and NGLs) represented approximately 40% of our total natural gas, oil and NGLs revenues for the three month period ended September 30, 2012 compared to 10% for the three month period ended September 30, 2011. Due to continued lower natural gas prices, we are focusing the majority of our 2012 drilling activity on the liquids-rich portions of the Marcellus Shale. If current trends of natural gas prices relative to oil and NGLs prices continue, and assuming that we successfully and timely complete our 2012 drilling activity, we expect our liquids revenues to continue to increase as a percentage of total revenues before hedging gains or losses for the remainder of 2012. NGLs prices continued to decline during the third quarter of 2012, largely attributable to a record-warm winter, a slowing global economy and growing NGLs supplies. We expect NGLs prices to remain depressed in the near-term, with some anticipated recovery by the end of the year. During the three months ended September 30, 2012, we had commodity derivative contracts covering approximately 89% of our natural gas production, which resulted in realized gains of $2.6 million and an increase in total price realized from $2.27 per Mcf to $3.20 per Mcf. The realized hedge impact includes a benefit of $222,000 for amortization of prepaid call sale premiums. Excluding the non-cash amortization, the realized effect of hedging was an increase in revenues of $2.4 million, which was comprised of $3.5 million of NYMEX hedge gains offset by $49,000 of regional basis losses and payment of deferred put premiums of $1.1 million. During the three months ended September 30, 2011, the . . .
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