Gastar Exploration, Ltd Q4 2010 Earnings Call

8/6/2019 Gastar Exploration, Ltd Q4 2010 Earnings Call

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Gastar Exploration, Ltd. Q4 2010 Earnings Call

Date Created: Apr-11-2011 Page 1 of 19

Gastar Exploration, Ltd. (AMEX:GST)

Earnings Call Transcript

Friday, March 11, 2011 10:00 AM ET

Call Participants

Executives Analysts

Lisa Elliott Joshua YoungVice President

J. Porter Ronald MillsChief Executive Officer, President, Chief Operating Officer

and Non-Independent DirectorJohnson Rice & Company, L.L.C.

Michael Gerlich Stephen BermanChief Financial Officer, Principal Accounting Officer and

Vice PresidentPritchard Capital Partners, LLC

Jeffrey HaydenRodman & Renshaw, LLC

Derrick WhitfieldCanaccord Genuity

Neal DingmannSunTrust Robinson Humphrey, Inc.


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Presentation

OperatorGood morning, ladies and gentlemen. Thank you for standing by, and welcome to the Gastar Exploration's FourthQuarter Earnings Conference Call. [Operator Instructions] I would now like to turn the conference over to Lisa Elliott withDRG&L. Please go ahead.

Lisa ElliottThank you, Alicia. And good morning, everyone. Before I turn the call over to management, I do have the usual items togo over. If you'd like to receive alerts to future news releases, please go to the Investor Relations page of Gastar'swebsite, that's www.gastar.com. Please sign up for those automatically. A replay will be available shortly by webcastwhere it'll be archived on the company's IR website, and a telephone replay will be available for one week. The phonenumber and access codes are in yesterday's press release.

Today, this call may contain forward-looking statements. And so management believes these statements are based onreasonable expectations, they can give no assurance that they will prove to be correct. These statements are subject tocertain risks and uncertainties and assumptions including, among other things, market conditions, oil and natural gasprice volatility, uncertainties inherent in oil and gas drilling, production in operations and estimating reserves,unexpected future capital expenditures and access to capital, competition, litigation, government regulation and otherfactors. Those factors are described in the company's Form 10-K, which was filed on Thursday, March 10, 2011, andcan be found in the Investor Relations section of its website.

Should one or more of these risks materialize, recent underlying assumptions prove to be incorrect, actual results mayvary materially from those expected. And today's call may also include a discussion of probable or possible reserves anduse terms like reserve potential and upside or other descriptions of non-proved reserves, which are more speculativethan the estimates of proved reserves and accordingly are subject to greater risks. Information related on this callspeaks only as of today, March 11, 2011, so any time-sensitive information may no longer be accurate as of the time ofany replay.

Now I'd like to turn the call over to Russ Porter, Gastar's President and Chief Executive Officer. Russ?

J. PorterThanks, Lisa. And good morning, everyone. And as usual, Mike Gerlich, our CFO, is here with me this morning. In 2010,we laid the groundwork to diversify our portfolio of opportunities from almost 100% reliance on dry gas with the potentialto produce substantial volumes of oil from our East Texas acreage and condensate and natural liquids from ourMarcellus acreage. We can't do anything about the poor natural gas pricing environment that I believe could be with usfor quite some time.

But our folks seen on the prospectivity of the Glen Rose and Eagle Ford/Woodbine formations or Eaglebine, as we referto it, that underlie our existing East Texas acreage and by acquiring additional acreage in West Virginia, Pennsylvania

with high-value condensate and natural gas liquids, we have positioned Gastar to benefit going forward from thehistorically high oil and natural gas liquids prices. This will continue to be our strategy for 2011 and until gas pricesimprove. In fact, about 59% of our drilling CapEx budget for 2011 will test these higher value liquids prospects.

Also in 2010, we established a joint venture with a strong financial partner, Atinum from South Korea, that will provide uswith the resources to dramatically increase our drilling program in the Marcellus. As 2011 got underway, we had cash inthe bank, no debt and tremendous opportunity. We'll go into more detail in a moment about our capital plans. I'd like tobegin with a look at our year-end reserve position plus highlights of the fourth quarter. Mike will then cover the financialdetails and I'll come back with a look ahead at the year and then our operational plans.


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Looking first our reserve position. Despite the poor natural gas pricing environment, we replaced more than 100% of ourreserves in 2010. At year-end 2010, total proved reserves were approximately 50.3 Bcf equivalent composed of 49.9 Bcfnatural gas, 51,000 barrels of oil. That's an increase of about 3% from 2009 reserve level. Of the 50.3 Bcfe, 83% areproved developed reserves. Roughly 90% or 45 Bcfe of our reserves are in East Texas, and about 5.5% in Appalachia,

and 4.5% in Wyoming. Our extensions and discoveries were 6 Bcfe plus an additional 2.6 Bcfe primarily related toupwards performance revisions. The PV10 value of our reserves at year end was $67.3 million using the 12-monthaverage first day of the month pricing method the SEC adopted at the end of 2009. That compares with the PV10 valueof $45.6 million at the end of 2009.

Quickly looking at financial results for the fourth quarter. Excluding the impact of an unrealized hedging loss and a smalllitigation expense accrual, fourth quarter earnings totaled $325,000 or $0.01 per share compared to the adjusted netloss of $748,000 or $0.02 per share a year ago. Please refer to the table at the back of yesterday's news release for acomplete list of special items in both years. On a reported basis, we had a net loss of $2.9 million or $0.06 per share forthe fourth quarter of 2010 versus reported net income of $12.9 million or $0.26 per share in the fourth quarter of lastyear. Keep in mind that in the fourth quarter of 2009, we recognized an additional gain of $13.2 million net of incometaxes related to the sale of our Australian assets.

For the full year 2010, adjusted net results were roughly flat versus 2009. Excluding special items in both years, 2010

net loss was $3.3 million versus $3.2 million in 2009. On a reported basis, the net loss in 2010 was $12.5 million versusearnings of $48.8 million in 2009. Again, that 2009 include $140.8 million after-tax gain from the Australian sale, partlyoffset by $68.7 million ceiling impairment. Again, those adjustments are detailed in the earnings release.

From an operational standpoint, by mid-year of 2010, we had resolved the problems with the Belin #1 and Donelson #4wells that disrupted our trend of growing production and total company production was up 14% from the third quarter.We expect to see more meaningful production growth throughout the year with first production from the Marcellusexpected around the third quarter of 2011. Mike will come back to this in a moment with some more detail as well as alook at pricing.

Looking now at our operating activity in East Texas. In late November, we began drilling the Belin #2 well, which is alower Bossier task a down turn default lock adjacent to the Belin #1 well. We reached a total depth of 19,650 feet at theend of February, and we logged approximately 130 net feet of pay at the lower Bossier within five separate sand

intervals.

Because of the continuing tightness in frac services, we're hopeful we can frac and complete the well and get it onproduction by late April. We hold a 66.7% working interest before payout in the Belin #2 well. As I mentioned in the lastcall, we plan to drill the Belin #3 well with spudding for that well planned in mid-March. The drilling of these twoadditional wells exposes us to meaningful potential reserve additions that will allow us to hold a sizable lease position inthe Hilltop area that would otherwise expire. These leases have Bossier and Knowles gas potential as well as Eaglebineoil potential. Again, we have 66.7% working interest in the Belin #3 well.

We also continue to drill and test oil potential in the Glen Rose and the Eagle Ford/Woodbine formations in East Texas.In late February, we frac-ed two Glen Rose tests that were drilled in the fourth quarter. The first was the Williams #2,which is an 8500-foot vertical well. The second was the Wildman 8H, which is a 4400-foot horizontal well, which wascompleted with an 11-stage frac. In early March, we commenced initial flow back operations. The Williams #2 was

initially flowing up 4.5 inch casing with almost an immediate show of oil. As we anticipated, we will be placing the well onride lift pump and we'll continue to monitor production. We also consider doing a dual completion in the Eaglebine in theWilliams #2 well later this year.

Regarding the 8H, the Wildman 8H, we're encouraged by the early daily fluid and oil rates. The initial seven-day flowingproduction averaged over 250 barrels of oil per day in excess of 1300 barrels of fracture stimulation fluids per day. We'reencouraged by these early flow rates, and we'll monitor the production longer term before determining whether toproceed with drilling additional Glen Rose wells. As we learned in the completion of the Wildman 6H, which is a naturallyfractured limestone, the Glen Rose requires a slightly different completion technique.


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We're using a slip water frac instead of a large prop frac. Total drilling completion costs for the Williams #2 and Wildman8H including frac-ing were approximately $1.5 million and $5.8 million, respectively. We have a 100% before payoutworking interest in both these wells. Under a development scenario, a horizontal Glen Rose well is estimated to costapproximately $4 million to drill it completely.

We continue to evaluate our first Eaglebine horizontal test, the Wildman 7H. As I mentioned last quarter, we had sometrouble with the lateral hole so we sidetracked it into the False Buda formation. After completing the full-end backapproximately 40% of the frac water of a 4.5-inch casing, we placed the well on a down hole ESP pump in late February.The ESP pump has allowed us to expedite the flow rates, and current production is averaging about 120 barrels of oilper day in excess of 1500 barrels of water per day. Since we didn't access a primary reservoir that we were originallytargeting, we're planning on drilling an additional horizontal Eaglebine test, the Wildman 9H, that I'll discuss in moredetail later. We're still on the learning curve for the Glen Rose and the Eaglebine objectives, but we're making progressin optimizing drilling and completion techniques and further defining the oil potential from our existing East Texasacreage. These formations have the potential to significantly change the composition, gas arch production profile andmaterially increase our NAV per share.

Now looking at our 2010 Bossier drilling activity. The Streater #1 well, which is a middle Bossier well that went onproduction in September 2010, is performing very well and was responsible for our overall production increase in the

fourth quarter. The Streater #1 came on production at a gross 7.6 million cubic feet per day and is currently producingabout 3.9 million cubic feet a day. It is producing from a single middle Bossier zone, but we plan to complete it in twoadditional zones once the current reservoir pressure declines. And I should also mention that the Donelson #4 producedan average of gross 10.8 million cubic feet a day in the fourth quarter and is still producing about 9 million cubic feet aday this month. You will recall that we had some drilling problems with that well last year. And it's been a great producerfrom the co-mingled B5 and B6 zones and has additional pace up the hole. After a casing class during recompletionoperations, the Belin #1 is continuing to perform well. It produced a gross 5.7 million cubic feet a day in the fourthquarter after returning to production in late June of last year and is currently still over 5 million cubic feet a day.

Now moving on to Appalachian. The acreage we acquired earlier this year is contiguous to our other acreage in MarshallCounty. It's located at PPG industries nature and chemical site along the Ohio River. We expect to begin drilling on thePPG acreage during the second half of this year. And we've identified as many as 30 locations to be drilled over the nextseveral years. These leases are in Marshall County, West Virginia and have a very liquids-rich area of the Marcellus.

Developing the rich gas areas on the Western side of the Marcellus Shale play is a key part of our 2011 strategy giventhe widening divide between natural gas prices and prices for oil condensate and natural gas liquids. The gas in thisarea has a BTU content 1300 and higher with condensate yields from 20 barrels per million cubic feet to 80 barrels permillion cubic feet of natural gas, so the economics to drilling these rich areas are very good.

Atinum is partnering with us on this acreage under the joint venture agreement. Gastar will pay 45% of the leaseacquisition cost or 50% interest. Initial drilling on this acreage will be eligible for the same drilling carry terms that weannounced when we formed a joint venture with Atinum last year. Actually, this means that we can use a portion of the$40 million carry for activity on these leases.

The approximately 62,000 net acres of leasehold we acquired in December is concentrated in Preston, Tucker andPendleton Counties of West Virginia. In addition to the acreage, we acquired a gathering system with 41 miles of 4-inch

and 6-inch steel pipeline, a salt water disposal well and five conventional wells producing about 500,000 cubic feet perday. The purchase price was $28.9 million. Atinum chose not to partner with us on this acreage package. We think thishad more to do with the timing and the transaction and the limited operating results that we have from this area ratherthan their view of the quality of these new assets.

We now have a total of approximately 81,200 net acres in the Marcellus. We've been trading acreage with otherproducers in order to create more efficient contiguous blocks of leasehold. This will allow us to do drill more wells withlonger laterals on acreage we have under lease. During the fourth quarter, we completed the drilling of our first operatedhorizontal joint venture, Marcellus Shale well, the Wengerd #1, in Marshall County West Virginia. Depending on theavailability of a frac crew, we hope to be able to frac the well in April and have it on production in May. Gastar and


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Atinum each have a 50% working interest in this well with Atinum paying 87.5% of the drilling and completion costs. Wewill plan on drilling five or six additional wells from this path.

Also an update on our pooled acreage projects in Butler County that Rex [Rex Energy] is operating. Rex is in the

process of drilling the horizontal portions of the seven wells that were spudded in late 2010. They've informed us thatthey plan to frac these wells in sequence and are targeting initial production in the fourth quarter of this year. Gastar andAtinum in our joint venture have a [indiscernible] being drilled from a single path at a gross cost of approximately $1million each. Our joint out-of-pocket share of this seven-well package is about $11.1 million, and we will have a 19.2%interest in each well. Atinum will also have a 19.2% interest but they will pay 87.5% of our joint costs.

I should also mention that in December, the joint venture entered into a gas purchase agreement with SEI Energy forfuture production from Marshall County, West Virginia. Initial term is five years with a five-year extension. This gas willbe processed at Cayman energy's midstream facilities and transported out of the area on the TETCO system. This is animportant factor in establishing the ability to invest significant capital dollars without continued delays in revenuegeneration.

We've also been able to secure a commitment for frac services for Marcellus wells we plan to drill this year along with adependable water supply and rig commitment that is nearly finalized. These steps position Gastar for success that will

materially impact our financial results and our reserve position. These accomplishments are the results of the efforts ofour chiefs of staff, along with our staff in Clarksburg, West Virginia lead by Mike McCown, our VP of Northeastoperations.

I'll come back to our future plans in Texas and Appalachian in a moment. But now, I ask Mike to provide additional coloron the numbers.

Michael GerlichThanks, Russ. And good morning, everyone. So that we can leave more time for your questions and for providing someadditional color around the things that are not explained in news release or the K, I'm going to skip going through thedetails of the income statement, which Russ summarized upfront. As a reminder, there is a table at the back of the newsrelease that walks you through all the unusual items for the fourth quarter and full years 2010, 2009. If you have any

questions, we'll be glad to cover those in the Q&A.

I will make a quick comment on the smaller of the two items we've broken out for the fourth quarter of 2010, which wasroughly $600,000 litigation accrual. The majority of this relates to a 2004 debt financing and a dispute that aroseconcerning the number of wells that the financing group was entitled to receive overriding royalty [ph]. This matter wentto arbitration in early January and was resolved through the payment of cash and a market repurchase of a portion ofthe overrides originally granted. The accrual reflects the settlement of this matter in a small accrual for some otherlitigation. We encourage significant litigation expense over the last couple of years, and we do not expect that trend tocontinue into 2011. An additional benefit to the settlements will be a decline in legal G&A cost as we move forward.

Looking quickly at cash flow. On a normalized basis, excluding the special items in both years that are included in thetable at the back of the news release, cash flow from operating activities before working capital changes for the fourthquarter was $4 million versus comparable cash flow of $2.2 million in the fourth quarter of 2009. For the full year,

normalized cash flow before working capital changes was $10.9 million in 2010 versus $16.2 million in 2009.

In regards to production. We exceeded our production volume guidance of the 23 million to 24 million cubic feet a dayfor the fourth quarter with average daily production of 25.8 million cubic feet equivalents compared to 22.6 million a dayin the third quarter and 23 million a year ago. We exceeded our guidance primarily due to shallower declines in ourrecently added East Texas Bossier wells. As Russ mentioned, we got a nice pump in production from the Streater #1well in East Texas, which produced an average of gross 5.8, net 4.6 million cubic feet a day in the fourth quarter.Average daily net production from Texas was 23.8 million a day, which was up 18% from both the third quarter andfourth quarter of 2009.


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Growth from East Texas more than offset the ongoing declines in Wyoming, where depressed Rockies natural gaspricing has dissuaded our operating partner from drilling any new wells, coupled with steps to reduce operatingcompression costs, which further reduced production. Our net share production from Wyoming last quarter was 1.6million cubic feet today versus 2 million a day in the third quarter and 2.5 million a day a year ago. We produced 400 Mcf

equivalent a day from our shallow conventional wells in Appalachia, which has held fairly steady over the last year.

Our production forecast for the first quarter of 2011 is about 20 million cubic feet a day to 22 million cubic feet a day. Wedo see this production significantly ramping up in the second half of 2011 as we bring on our Marcellus shale productioncoupled with our continuing East Texas drilling efforts.

For the full year, we see production averaging between 27 million cubic feet a day equivalent and 30 million cubic feet aday equivalent with 6% to 8% attributable to oil and condensate production. The growth in projected oil and condensateproduction is significant considering we're currently almost 100% natural gas. Plus the oil production estimate assumesno further drilling in East Texas beyond the additional Wildman 9H Eaglebine test well that Russ mentioned previously.

Natural gas prices remain soft in the fourth quarter. They were higher in January but they have declined again inFebruary and March. We had a $2.7 million of unrealized hedging loss and a $2.1 million realized hedging gain in thefourth quarter. As a result of our hedging programs, our fourth quarter realized natural gas pricing increase from $3.01

per Mcf to $3.90 per Mcf. That's compared with a realized price of $3.60 per Mcf a year ago and $4.09 per Mcf for thethird quarter of 2010.

The realized hedge impact includes a non-cash amortization benefit for prepaid foot purchases and call sale premiumsof $169,000. If you exclude the non-cash amortization, the realized effect of hedging would have been $1.9 million,which is composed of $2.9 million of Nymex hedge benefit, offset by 331,000 of regional basis losses related to thecontractual differentials that Houston ship Channel in Colorado interstate gathering and payment of deferred putpremiums of $659,000.

Excluding non-cash amortizations, the actual net cash benefit of our hedging for the fourth quarter was $0.82 per Mcf,which includes a reduction of $0.28 per Mcf for deferred put premium costs plus $0.14 of basis losses. Approximately74% of our natural gas production was hedged to provide downside protection during the fourth quarter.

For 2011, a significant portion of our estimated natural gas production was hedged either through producer three-waycollars for approximately 15,300 MMBtu per day with a weighted average floor of $6.12, short floor of $4.19 and a ceilingof $7.65 plus protective put spreads for approximately 2700 MMBtu per day with an average floor of $6 and a short putat $4 and fixed price swaps covering 2000 MMBtu per day with a based fixed price $6.11. In addition for Q1 2011, wehave short calls covering 2500 MMBtu with a ceiling of $9.15.

For 2011, we continue to carry basis hedges of approximately 10,000 MMBtu per day at a negative $0.23 per usageship channel and 800 MMBtu per day of Colorado interstate gathering basis at a negative $1.21. The HST basis hedgesare for the period January to June 2011. Due to current low Henry Hub natural gas prices, these basis differentials arecurrently projected to be negative only $0.07 and $0.39, respectively, for 2011.

For 2012, our hedges are currently composed of protective foot spreads for approximately 13,000 MMBtu per day with aweighted average floor of $6 and a short put of $4, producer three-way collars for approximately 5400 MMBtu per day

with a weighted average floor of $6, short put of $4 and a ceiling of $7.39 and a recently added fixed price swap of 2000MMBtu per day at a base fixed price of $5.05. We have no basis hedges for 2012.

We will continue to watch the market for opportunities to add additional natural gas hedges and prices that support ourcapital program and possibly all volume hedges as oil production increases. One thing I'd like to point out about theaccounting treatment of our hedging program for purposes of modeling that I think may not be very well understood. InDecember 2009, we added significant put spreads to hedge volumes for the period July 2010 through December 2012.We elected deferred payment of the put premiums until the hedge production month becomes the prop productionmonth.


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The remaining deferred put premium liability is approximately $3.5 million for 2011 and approximately $4.7 million in2012. These put premiums are currently netted by the counter party against the benefit derived from our hedgingprogram. The deferred put premiums reduced our realized cash benefit from [ph].

Looking at some of the key expense items in the fourth quarter and our guide in 2011. We continue to see improving atleast operating expense. Total LOE was flat versus the prior quarter and the year-earlier quarter at $1.5 million. On anMcfe basis, LOE declined to $0.62, which was $0.12 lower than the third quarter and $0.08 lower than a year ago. Theper unit decrease between the third and fourth quarter of this year was mainly due to higher production volumes andlower work over costs.

We expect first quarter LOE to be in the $1.7 million to $1.9 million range as we anticipate an increase that for loantaxes and work over costs. Estimate expected to work over costs anticipated growth in production, we are hopeful we'llsee continued improvement in LOE per Mcfe as 2011 progresses.

Our DD&A rate was $1.37 per Mcfe versus $1.03 a year ago and $1.28 in the third quarter. The increase over prior yearis mainly the result of crediting of the East Texas gathering system sale proceeds to the full cost pool in the fourthquarter of 2009 and additional capitalized costs. Transportation expenses were $1.1 million in fourth quarter versus$557,000 a year ago. This reflects the gathering charge that we began paying in early November 2009 following the sale

of our East Texas gathering system, partially offset by lower costs at Wyoming.

We expect transportation costs to continue to be in the $1.1 million to $1.2 million range for the first quarter. G&Aexpense was $3 million for the quarter versus $3.8 million in the third quarter and $4 million a year ago. Excluding non-cash stock compensation expense of $413,000 in the current fourth quarter and $780,000 last year's fourth quarter,cash G&A expense was $2.6 million versus $3.1 million in the third quarter and $3.3 million a year ago.

The main reason for the decrease in G&A was primarily related to lower legal costs, partially offset by higher personnelcosts in the current quarter versus the prior periods. Our legal expense for just under $1 million lower than in the thirdquarter, following the settlement of the ClassicStar litigation. First quarter cash G&A expense should be in theneighborhood of $2.4 million to $2.6 million with non-cash G&A in the $800,000 range for the quarter.

Looking at the balance sheet, at year end, we had cash and cash equivalents of $7.4 million, and we had nothing

outstanding on our revolving credit facility. The revolver has a borrowing base of $47.5 million and is scheduled for itssemi-annual borrowing base redetermination in May. We currently have $17 million outstanding under the facility.

You'll recall that in December, we raised a net $52.5 million during an underwritten public offering of common shares,which we used to fund the $29 million Marcellus acquisition and the initial $18 million payment for the ClassicStarlitigation settlement we announced in December, as well as for general corporate purposes. We believe that betweeninternally generated cash flow from operations, contributions from Atinum from the Marcellus drilling projects andavailability under our revolving credit facility, we'll have sufficient liquidity to support our 2011 planned explorationdevelopment program in both of our core areas. If additionally, liquidity is needed, our focus will not be a common equityoffering but possibly preferred share issuance, joint venture or debt.

Looking at CapEx, total net oil and natural gas capital expenditures totaled $17.7 million in the fourth quarter, whichincluded $13.4 million in Texas and $4.3 million in Appalachia and other. For the full year, net CapEx was $62.6 million,

of which $39.7 million was in East Texas and the balance to Appalachia.

As Russ will detail, we're planning for higher level activity in the Marcellus than originally projected so our total CapExbudget for 2011 is $83.6 million. We plan to spend $30.5 million to pursue both oil and natural gas drilling opportunitiesin East Texas. $23.7 million is budgeted for the Marcellus Shale for drilling, completion of infrastructure costs and is netof the contribution Atinum will make in our joint venture projects.

Keep in mind that the drilling carry into our joint venture with Atinum will fund additional portion of share by total CapExfor Appalachia next year. Gross capital expenses for the Marcellus program this year including Atinum's contribution isabout $141 million and if we estimate that we will have full year and the remaining carry balance by early 2012. We have


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budgeted an additional $22.5 in lease acquisition costs, $3.5 million for seismic and $3.4 million for capitalized interestand other costs.

Now I'll turn it back to Russ to go over operational plans for the rest of the year.

J. PorterThanks, Mike. In East Texas, as previously discussed, we plan on drilling an additional Eaglebine well, the Wildman 9H,which will be a 4200-foot horizontal test. We expect to spud that well later this month. The Wildman 9H will target theportion of the Eaglebine formation that we've missed in the Wildman 7H. We'll have a 100% working interest in the welland drilling and completion cost is estimated to be $6.3 million, including $4.3 million of fracture stimulation andcompletion costs. We'll again use an easy swell completion and anticipate performing 17 fracs during the completion.

Though drilling is only estimated to take 25 days, we're estimating that the well will not be in production until late secondquarter or early third quarter due to anticipated delays and scheduling the frac services. We'll evaluate the longer termresults of our two Eaglebine tests before deciding to proceed further with the program in 2011.

In March, we expect to spud the Belin #3, which will again be a lower Bossier test offsetting the Belin #2. We are also

anticipating in the late year lower Bossier exploration test on the northeastern portion of our acreage. This area willinitially be explored jointly with EnCana with our participation in this well to be in the range of 30% to 50%.

Our 3D seismic appears to show a similar deep structure to our Hilltop area in the Northeast portion of our acreage.Drilling on that northeast portion could de-risk an additional portion of our exploratory Bossier position. Of the $30.5million in drilling, dedicated to East Texas, $14.9 million or nearly 50% is dedicated to exploring our oil objectives in thearea as opposed to natural gas. However, if results for our oil efforts are positive, we would not hesitate to buy additionalcapital to our East Texas program in 2011.

The success we've had in the Bossier from the Donelson #4 and Streater, confirms our belief that we have many yearsof drilling opportunities in East Texas. But if natural gas prices remain below $5 per Mcf, we'll continue to curb ourBossier activity in favor of other higher value opportunities.

In Appalachia, we're looking at accelerating our Marcellus drilling program beyond what we have previously discussedwith a focus of the liquids-rich area of our joint venture acreage. With the drilling portion of the Wengerd 1H nowcomplete on our original Marcellus acreage, we expect to spud the next horizontal well from the same pad in partnershipwith Atinum as soon as the drilling rig is available.

We anticipated drilling the first horizontal well on the new PPG acreage during the third quarter and we'll likelycommence drilling on four wells there in partnership with Atinum. As a part of the joint venture, we plan to commencedrilling operations on a total of 27 operated horizontal wells, of which 10 will be top-holes only, 17 will be drilled encased.Of those 17 wells, 10 will be frac-ed and 10 turned to sales by year-end 2011. This acceleration programs should allowus to ramp up our liquids-rich production late in the year with that activity momentum carried into 2012. In addition, weand Atinum will be participating in the previously discussed Rex operated wells during 2011.

Outside the joint venture, we plan to drill one horizontal this year on the Marcellus acreage on the large package risk

acquired in December. This test well will likely spud sometime in the second quarter.

I'm extremely pleased with the position we've been able to carve out in the Marcellus shale and with the economics ofour future projects. We got in early at attractive prices per acre, and then teamed up with a strong financial partner whosgoing to allow us to dramatically increase our drilling pace by shouldering the majority of the drilling costs.

Further, we were able to expand our footprint through the acquisition we made in December at only $410 per acre. Andin February, we acquired acreage in an ultra liquids-rich portion of the shale play where the economics are outstanding.We estimate that we currently have approximately 9,800 net acres in the liquids-rich sweet spot, or assuming 100 acrespacing room for about 93 wells that should produce high BTU gas and meaningful NGL and condensate volumes.


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These activities alone will significantly change and enhance Gastar's revenue, cash flow and production profile, both interms of oil versus gas and in terms of longer RP ratios. As Mike said a moment ago, we plan to spend about $23.7million net for our share of drilling completion and infrastructure costs in the Marcellus. In addition, $30.9 million is year-marked for acreage acquisitions within our Atinum joint venture as we focus on further blocking up our acreage position

to accommodate longer laterals.

$4.1 million is dedicated to lease acquisitions in the area of our December acquisition, and $4.5 million is dedicated toEast Texas lease renewals and additions, bringing our total 2011 land budget to $22.5 million. A portion of these leaseacquisition funds may not have to be spent if we continue to have success trading acreage with other operators.

We are very anxious to continue testing the oil potential in our East Texas acreage. I think it is worth reminding everyonethat we do not have to invest capital dollars in acquiring additional acreage with oil potential. We are drilling the sameacreage that we originally acquired for its deep Bossier potential. The Wildman 7H well didn't test the Eaglebine but it'sproducing oil from the False Buda and probably from some of the porous reservoir rock in the Eaglebine section.

This confirms that the entire Eaglebine section is oil saturated, naturally fractured and over pressured. All keyingredients for successful oil resource play. As is the case with these type resource plays, the early wells areexperimental and necessary in order to crack the code on drilling and completion techniques.

That sums up our prepared remarks. And at this point, we'll open up for questions and answers.


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Question and Answer

Operator[Operator Instructions] Our first question comes from the line of Neal Dingmann with SunTrust.

Neal DingmannA couple questions. First, Russ, in East Texas, the 7H I guess versus like the 9H, you mentioned sound like the fracsyou would say 17 stages on this one. And would you go for the same formations in the Eaglebine in the False Buda?And if so, then we just co-mingle? I guess what I'm not getting at is how do you -- based on what you learn on the 7H?How is this 9H going to be different?

J. PorterThe 9H is different, Neil. The 7H, the lateral's portion of the well was drilled actually down in the very bottom of theEaglebine section, in on what we call the False Buda. The 9H is going to be drilled up at about 400 feet shallower thanthat in what we consider the heart of the best shows within that Eaglebine section. The 7H originally was targeted forthat. But we had hole stability problems so we dropped the well down into the False Buda because we knew we couldget a completion down there. We had some evidence from completion companies of 400 foot to 600 foot frac growth insimilar zones. We run microseismic on that well and we only saw about a 200, 250 feet of frac growth. So we'vebasically didnt test the reservoir that the 7H was originally designed to test before we drilled it. The 9H well is going totest what we consider the heart of the Eaglebine oil potential, which is also the same zone that some of the surroundingoperators are having some pretty material success in. So it's another Eaglebine well that's going to be drilled within adifferent section of the Eaglebine. And if we get a couple of hundred feet of frac growth again there, then we should bereally testing all the best potential with the 9H.

Neal DingmannAnd it sounds like there or over in the Appalachian like with around the Wengerd the fracs still seem extremely tight. I

mean you've been debating about completing these long-term frac deals that some of the peers are doing or what's yourthoughts on kind of both these areas around fracs or other services, remainder of this year into next year?

J. PorterWell, we are very pleased that we've got a deal that we are papering right now with BJ to assure that we've got all thefrac services we need for our accelerated Marcellus program for this year. So thats really not going to be an issue in theMarcellus. In East Texas, because we don't have a lot of future activity planned, we're not going out and signing any sortof long-term deal. But we do have frac dates scheduled with several providers. And there'll be some delays but therewon't be anything that we can't plan around and work around in East Texas.

Neal Dingmann

And then over -- if you get that Wengerd #1H frac-ed, I was wondering how fluid I guess your plans are? I mean, howmany wells you kind of laid out and mentioned what you think you can drill? Is it based on results kind of youll movearound is there still some signs here, or you're pretty convinced on...

J. PorterEverything we're drilling in the Marcellus. There's so much activity around us that we don't need a lot of science, of reallynot a lot questions what results are going to be. And so we're going to execute the program and I think you'll see a bigimpact on the company by the end of the year from that Marcellus program alone.


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Neal DingmannLast question. Just over back to East Texas on the -- after Belin #2 well, I'm just wondering as far as thickness offormation and if you'll co-mingle on that? And what are the plans remainder of the year sort of the net or are you givenobviously the attractive potential you have over with the Marcellus and then in the Eagle Ford?

J. PorterThe Belin #2, we're going to complete it initially in probably two zones and then we'll produce those for a while then we'lladd some of the other zones probably a year down the line. Belin #3 is our only other planned closure activity for thisyear. With the possible exception of a potential joint well with EnCana up in the northeast portion of our acreage late inthe year.

OperatorOur next question comes from the line of Ron Mills with Johnson Rice & Company.

Ronald Mills

Question on the Glen Rose. Can you provide a little bit more color on that Glen Rose horizontal? It seems like reallystrong rates based on where you are in the fluid recovery. Are you still seeing an increasing oil cut and relative toexpectations, what do you think about at least early performance of that well and then further on you had, I think 24, 25potential locations identified in the Glen Rose. As you evaluate more of your acreage, do you think that more of youracreage could have additional Glen Rose opportunities?

J. PorterYes, Ron. I guess, first starting with the Glen Rose well that we've got now, we are seeing increasing oil cut. It's stillproducing a significant amount of frac fluid back. And hopefully what we'll see is that as water production goes down aswe recover those frac fluids and we'll continue to increase the oil cut. We're really encouraged by the 250 barrels a daywe're seeing right now because it is so early in the life of it. If you look at where we are now, probably an educatedguess on EUR would be in the 150,000 to 175,000 barrel range. If these wells are 150,000 barrels and 250 barrels a day

at the type costs we're looking at, we're looking at in the 40% IRR range. So very economic. We are looking at additionalGlen Rose potential over our acreage. And we're about 30 offset locations now. I think that's going to expand as ourgeologists and geophysicists take a harder look at this now that we've got some initial success. And I wouldn't besurprised if we come up with another 15 or 20 potential locations.

Ronald MillsOkay. And you mentioned up in the Marcellus, you obviously were talking with BJ on the frac. You have a marketingagreement for the production and you're in discussions on the rig. Is the plan from an operating standpoint to have a onerig or would you need two rigs to execute that 20-plus operated, 25-plus operated well program?

J. Porter

We are going to have a top-hole rig that we'll be working throughout the year, really just the drilling the vertical section ofthese wells. We're going to have at various times during the year, two rigs drilling horizontal wells. We've got one ofthose rigs lined up for a portion of the year, and we're working on getting one of these hopefully one of these supersingle-type rigs that move in a small number of loads and are sort of purposely built for the Marcellus and we probablywouldn't hesitate to enter into one or two year contract or one of those because you know we're going to have asubstantial amount of activity even if we just limited it to this liquids-rich sweet spot, we've got more than three yearsworth of drilling to do.

Ronald MillsOkay. And then in terms of the timing. I know you're waiting on Cayman for the gathering lines and everything for your


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Wengerd well. Looking forward in terms of the way the development plan is laid out other than the timing of fracs, how'sthe infrastructure situation laid out relative to your drilling plans, i.e., are there going to be any potential bottlenecks orare those being [ph]?

J. PorterWell, we don't anticipate any bottlenecks on that with the Wengerd well. Was a little bit of delay in frac-ing means thatCayman will be ready to pick up gas when that well is frac-ed and we've built our drilling program around as a key factorability to get gas out of there. So we built it around Cayman's capacity to get the gas out. And we've -- in setting outthem, there know where all our locations are. We're planning where the central receiving points will be. So we reallydon't expect any delays as a result of pipelines. The other thing there that some people may not realize is critical is thatwe're just about to finalize all the terms on source of water for us that would allow us almost 20,000 barrels a day ofwater capacity, which means that we can move a lot of water around and we can put water on location quickly so wecan run the zipper fracs and we can get these wells completed without a delay, waiting to find or fire pump water.

Ronald MillsAnd then from a timing standpoint, you're going to drill this Wildman 9H. You're going to continue to monitor the Glen

Rose well and then I guess at current plans you just have plans to drill that one more Eaglebine well. What would drivethe potential for deciding to drill more liquids wells in East Texas this year? And from a timing standpoint, would that bemore about third quarter or fourth quarter type decision because you want to have significant production history? Is thatthe right way to look at it?

J. PorterYes, Ron. That is the right way to look at it. We're going to drill this 9H well and we'll get it frac-ed and put online andevaluate it. And by the time we get all that done, then if we decide to accelerate the program, it would be probably latethird quarter, fourth quarter type of activity, which of course, is also going to be impacted by what the results have beeneverywhere else in the company and what our capital availability looks like and all those other issues that go into thattype decision.

OperatorOur next question comes from the line of Steve Berman with Pritchard Capital Partners.

Stephen BermanJust one housekeeping item here. Russ, can you repeat the cost on the Wildman 8H. I didn't hear that. Thought I heard$5.8 million that's...

J. PorterThe Wildman 8H was $5.8 million. And as we said, future wells going forward, for that we're looking at -- what's thenumber Mike? Approximately $4 million.

Stephen Berman[ph] EnCana costs, who's going to operate that?

J. PorterIt depends on which track the well gets drilled on. I wouldn't be surprised if it's [ph] EnCana has a little bit more interestthan we do. So they would probably operate the initial well.


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Stephen BermanAnd at this point, no plans to do any Bossier recompletions at any of the existing wells?

Michael GerlichThis is Mike. There's actually two recompletions planned in some of our existing wells for the year. They're basicallygoing to be focused really on the Donelson ford and the Streater.

Stephen BermanAnd in terms of current liquidity, the press release had $7 million of cash at year end and $17 million drawn currently onthe revolvers. What's the current cash position, if you could say that?

J. PorterWell, obviously, our cash position at this point isn't excessive. Otherwise, we wouldn't be pulling down the line. Onething I did fail to mention is we have not been reimbursed yet by Atinum for their share of the PPG acquisition and sotheir share of that is just north of $5.5 million. So we should be getting that in here fairly soon. And obviously that will

present us an opportunity to pay down our revolver at that time.

OperatorOur next question comes the line of Jeff Hayden with Rodman & Renshaw.

Jeffrey HaydenI'm just wondering if you can talk a little more detail about what you saw in the 7H and what are we going to dodifferently in the 9H in terms of trying to help with those stability issues?

J. Porter

As far as the 7H, we drilled the original hole 5000-foot lateral in the zone that we wanted to target but we were not ableto keep the well open in order to run the easy swell system. Going back over and looking what we were doing andlooking what some all-set operators were doing, the biggest difference was the mud systems. We're actually going to runa mud system thats oversaturated with chlorides in the 9H well, which should resolve that sort of heaving shaleproblem. So we'll put the 9H where the 7H was originally targeted within the formation. On the 7H, we did runMicroseismic and that allowed us to see what type of frac growth we did or didn't achieve. We got on average about 200feet of frac growth from the Microseismic data that we gathered, which was really a pretty good investment for usbecause without that, we never really know exactly where this oil were producing is coming from. So what we learned isthat this oil we're producing is coming from probably the False Buda, maybe a little bit from the Buda, which we frac-eddown into and then from just the very lowest extent of the Eaglebine reservoir quality rock. So what we're going todifferent is put the well about 400 feet shallower in the section, drill a horizontal and then put the similar type frac job onit and hopefully just get the same type frac connected to better reservoir than what we've got right now.

Jeffrey HaydenAnd some of your neighbors who've been having good results out of the formation, have you kind of a seen anyexamples from them with maybe before they started tweaking up their completion design. They had kind of a similarissue with the formation integrity in the hole?

J. PorterNo. We've seen a very similar from some of the Australian operators but we can't discuss anything we've seen in detailbecause most of that we're under confidentiality agreement on.


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Jeffrey HaydenOkay. Fair enough. Just one last one. I'm giving kind of the ramp-up implied by kind of the Q1 guidance and the full year

guidance, where do you guys kind of think you're 2011 exit rate is going to be?

Michael Gerlich2011 exit rate?

Jeffrey HaydenYes.

Michael GerlichI would tell you at this point it's going to be probably somewhere in the $40 million to $42-ish million range.

Jeffrey HaydenOkay. And what do you think the liquids percent is going to be out of that number?

Michael GerlichYes, it'll be about 8% to 9%, by that time.

OperatorOur next question comes from the line of Derrick Whitfield with Canaccord Genuity.

Derrick WhitfieldThe - getting back to Glen Rose. Could you guys comment on what you're expecting as you move up this from thetrend? I'm specifically interested in locations you identified in your latest PowerPoint away from the 6, 8. I think it's thesix in the Wildman 8?

J. PorterBasically, what we're doing there is we're moving a long trend along the flexures where we think the natural fracs havebeen created. We've got a good test now on one area. We've got an earlier well mono fracs #4 that we DST-ed over 200barrels a day from which is up to the north of this and we see a number of locations around it. And we're starting topush that examination into some other portions of our acreage of kind of staying along that structural nose that we seethere. So like I said, I think you'll eventually see us talking about a number of new locations or additional future locationsfor the Glen Rose as we spend more time on it now that we know there's some real potential there.

Derrick WhitfieldAnd then understanding it's still early days in the appraisal portion of your Eagle Ford or Eaglebine trend, could you helpus frame up the potential based on the Microseismic analysis you've conducted and the data you analyzed from theindustry? I guess I'm specifically interested in maybe how the geology in your area compares with that to the South inBrazos and Burleson counties?

J. PorterI don't know about the specifics of those two counties. But then again, I know that in general, the southern part of the


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play, one of the things that's made it work is that there is a high percentage of limestone within that Eagle Ford section.We're seeing similar percentages of limestone up here where we are and what we call our Eaglebine, which is its EagleFord in some parts of the world, it's Woodbine in others and we're right on the transition of where you call it one thing orthe other, so we made up our nomenclature. But we're seeing high percentages of lime, which has very positive

implications for how these reservoirs can be completed and whether they'll take a frac and the frac can be effective inthem. They're brittle. They're not ductile, which is I think one of the keys that's going to make it work. As a far as overallpotential, we haven't changed our outlook at all. We still we got about 125 potential locations if we can prove that it'seconomic.

Derrick WhitfieldAnd then maybe what type of porosity readings are you guys seeing and then what's your pressure gradient in thisarea?

J. PorterIt's slightly over pressured. I don't have exact gradient at my fingertips here. But we've had shows in the Eaglebine thathave taken at roughly 6,500 feet have taken nine to 11 pound mud weights to kill, so it's definitely over pressured. And

the fact that this 7H well produced naturally up 5-inch casing for so long shows that it's slightly over pressured. Whatwas the second part of your question?

Derrick WhitfieldIt was the porosity reading. If you guys have any measurements on that?

J. PorterI'd say we're seeing north of 8% porosity is all I want to say about that right now.

Derrick Whitfield

Moving over to the Appalachian basin, if you guys had a chance to evaluate the Uinta shale at any capacity to date?

J. PorterWe have not. There has been Uinta shale test just offsetting our position up in Butler County. A test was actually inBeaver County, but our acreage is in Butler. We heard that there is some tests upcoming that is going to have an impacton Western acreage in West Virginia. And we've seen the maps that probably you've seen that some of the otheroperators are publishing and that some of the academics are publishing. At this point, all I can say is that it's likely we'regoing to have Uinta potential on a portion of our acreage but we cannot quantify that right now.

Derrick WhitfieldAnd then on the Marcellus, could you help us quantify how much of your acreage is now located in strategic and efficient

blocks following the recent land work you've done?

J. PorterO

I can't give you a percentage, but I can tell you that we're blocking up for our 2011 program, we've got -- we've beenable to, through trading with other operators really assure ourselves that almost every well we drill is going to be at least4,400-, 4,500- or 5,000-foot laterals at minimum. Whereas if we hadn't done these trades, we'd be looking at some wellswith maybe a couple of thousand feet of horizontal and other wells filled from the same path with 4,000 or 5,000 feet. Soit's going to make our overall program more efficient. It's an ongoing process. We're continuing to talk to other operators


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about trading acreage and we're going to buy some additional acreage to fill in some of those gaps, but I can't tell youwhat percentage of our acreage is within one of those or what isnt right now, but I can tell you that essentiallyeverything that we're going to drill in 2011, 2012 over there in Marshall or Wetzel county area will probably be in an areawhere we [ph] up like that.

Derrick WhitfieldRuss, it sounds like you got at least two years in runway with a one-rig program.

J. PorterWe probably have two years of run rate with a two-rig program.

Derrick WhitfieldAnd one more question if I could. This is on the Eagleford. Could you break down that $4 million AFE that you'dmentioned earlier? Interested in dry hole costs, completion costs, et cetera.

J. PorterWell, for the Eagle Ford, we're looking at a total AFE of about $6 million. Yes. For the Eagle Ford, Eaglebine, it's $6million to drill and complete, probably $2 million of that is the dry hole costs and the rest is frac services.

OperatorAnd our final question comes from the line of Josh Young with Young Capital Management.

Joshua YoungQuick question for you on this Glen Rose, the Wildman 8H. It's currently producing 250 barrels of oil a day and I thinkyou said about 1,300 barrels or so of production fluids a day or completion fluid. It sounds like you're sort of guiding to a

completion rate or a final production rate of around that 250 barrels a day even though in many other wells and in manyother oil wells when there's that amount of completion fluid coming back and that amount of oil, the ultimate initialproduction rate is announced and that ends up working out tends to be higher maybe 500- or 600-something barrels aday. Can you give us some idea of where you might expect it to level out in sort of what the rate of oil production hasbeen in finding by and sort of where you could see it leveling out?

J. PorterJosh, I mean anything we would tell you beyond what well is producing right now would really be speculation becausethis is our first well in this area. We have seen the oil cut continue to improve and we're as anxious to know the numberis as you are. Yes, it's possible the well could continue to go up on a daily oil rate. It could flatten. We don't know what toexpect because this is really the first Glen Rose, horizontal Glen Rose completion that's anywhere near in the area. Sonext quarter's call we'll be in a position to update everyone further. And certainly if you hear us talking about additional

activity there, drilling activity then you're going to know that we think that the economics are pretty strong. But the basisof your question is correct. There are similar plays where you do continue to see your oil take to go up as you clean upthe well, and get those frac fluids back, but I really don't want to sit here and speculate on what that number could be.

Derrick WhitfieldAnd then that of the EUR of a 150,000 barrels would be if the well sort of flattened out at this 250 barrels of oil a day andthen started to climb?


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J. PorterThat would be, that's assuming you had a peak rate of 250 barrels of oil a day and then you started climbing from there.

Derrick WhitfieldOkay. So it sounds like there's potential upside in both from the oil rate again, from the EUR perspective and it just youguys are trying to be conservative and not say anything beyond what you're actually seeing right now in the well?

J. PorterYes. That's a fair assessment.

Derrick WhitfieldAnd then can you talk a little bit about some of your thoughts on financing? I know Mike talked a little bit about thepossibility of debt financing or preferred or some of the other sort of options that you have other than raising equity and Iguess just some of your thoughts around that?

J. PorterAs Mike mentioned, if we needed additional capital, which is not a definite. But if we needed additional capital, we arevery focused on not selling common stock. I mean the scabs haven't healed yet from our last experience with that, andwe're looking at what some of the other EMP companies have done as far as some perpetual preferred issuances,which we think are fairly attractive both to the investment community and as a vehicle for financing. And we're looking,we're examining that. And we'll look at whether or not it's too early to sort of sway in a permanent portion of debt capital.But we're evaluating all those opportunities. Again, with a goal of not selling common stock.

Derrick WhitfieldAnd then final question regarding the exploration activity on the northeast portion of your acreage in Texas with EnCana,did you guys look at just going a non-consent on that one well letting them sort of explore it, see what they find and then

you'll have acreage around the area without having to deploy capital dollars into EnCana's exploration budget?

J. PorterWell, the well has not been proposed. So Im not going to sit here and tell you whether we're going to consent it or notconsent it, but the tracks that we're looking at. We have leasehold interest in those tracks as does EnCana. And to behonest I'm not sure if EnCana would drill the well if we'd not consented so we're going to examine that as it gets closerand as it gets more definite.

Derrick WhitfieldIt sounded like it was a little bit nearer-term than what you're saying right now.

J. PorterIt's fourth quarter type activity.

OperatorThank you. Mr. Porter, there are no further questions at this time. Please continue.

J. Porter


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Okay. Thank you, everyone. We appreciate you taking the time to be with us on the call. And as always, we usuallymention, if you have any other questions that we can answer, feel free to contact Mike or myself in our Houston office.

OperatorLadies and gentlemen, this concludes the Gastar Exploration's fourth quarter earnings conference call. If you'd like tolisten to a replay of today's conference, please dial (303) 509-3030 and enter the access code of 4406342. We wouldlike to thank you for your participation. You may now disconnect.


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Gastar Exploration, Ltd Q4 2010 Earnings Call

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Transcript of Gastar Exploration, Ltd Q4 2010 Earnings Call