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Executives

Darby Sere - President & Chief Executive Officer

Bill Rankin - Executive Vice President & Chief Financial Officer

Bret Camp - Senior Vice President of Operations

John Gibson - Vice President of Corporate Development & Marketing

Tony Oviedo - Vice President & Chief Accounting Officer

Steve Smith - Treasurer

Analysts

Kevin Smith - Raymond James

Phil McPherson - Global Hunter Securities

Mark Lear - Sidoti & Company

GeoMet Inc. (OTCQB:GMET) Q4 2008 Earnings Call March 13, 2009 11:30 AM ET

Operator

Good morning. My name is Amanda and I will be your conference operator today. At this time, I would like to welcome everyone to the GeoMet fourth quarter and fiscal 2008 results of operations and financial conditions conference call. All lines have been placed on mute to prevent any background noise. After the speaker’s remarks, there will be question-and-answer session. (Operator Instructions)

I would now like to turn the conference over to Mr. Steve Smith, Treasurer of GeoMet. Please go ahead sir.

Steve Smith

Thank you Amanda, good morning everyone. Earlier today GeoMet issued a press release announcing our fourth quarter and fiscal 2008 operating results and results of financial condition. If you need a copy of the release one is available on our website www.geometinc.com.

Today you’ll be hearing from Darby Sere, GeoMet’s President and Chief Executive Officer and Bill Rankin our Executive Vice President and Chief Financial Officer. Also present today are Bret Camp, our Senior Vice President of Operations; John Gibson, Vice President of Corporate Development and Marketing; and Tony Oviedo, our Vice President and Chief Accounting Officer.

Statements made today regarding GeoMet’s business, which are not historical facts represent forward-looking statements that involve risks and uncertainties. Actual results may differ materially from those indicated by the forward-looking statements. For a discussion of the risks and uncertainties, which could cause actual results to differ from those contained in the forward-looking statements, please see forward-looking statements and risk factors in our filings with the Securities and Exchange Commission.

In the filings with SEC, oil and gas companies may disclose only proved reserves that have demonstrated by actual production or conclusive formation test, to be economically and legal produce able for under existing economic and operating conditions. During this call, we will use the term probable prescribed reserves that may potentially be recoverable through additional drilling.

The SEC guidelines to not allow companies to include probable reserves in the filings with the SEC; these estimates by the nature are more speculative than estimates of proved reserves. Investors are urged to closely consider this disclosure together with those in our filings with SEC. We disclosed probable reserves because we believe coalbed methane reserves have unique characteristics and this disclosure provides valuable information to our investors.

The terms finding and development cost, adjusted EBITDA and adjusted net income for non-GAAP measures. Please refer to our press release this morning for a reconciliation of adjusted EBITDA and adjusted net income and our website for our calculation of our finding and development cost.

At this time, I’ll now turn the call over to Darby.

Darby Sere

Good morning everyone and thank you for joining us today. We are pleased to welcome you to GeoMet’s fourth quarter and fiscal 2008 conference call. As we reported earlier today GeoMet achieved record gas sales volumes, revenues, adjusted net income and adjusted EBITDA in 2008.

In addition, a significant risk associated with our Virginia pipeline was eliminated by a unanimous favorable decision by the Virginia Supreme Court in September. Unfortunately, the year ended with gas price is down over 50% from the middle of the year and they are down another 30% since then.

GeoMet is prepared to adjust to the challenges of persistent low gas prices and uncertain capital markets. It is impossible to know how long these conditions may last. Therefore we like most of the companies in our industry have adopted a conservative strategy to preserve our capital and liquidity.

In 2009, we will limit our capital expenditures to an amount which approximates our internally generated cash flow, a significant reduction from 2008 expenditures. However, we expect the cost to drill, complete and equip wells, to be much lower in 2009, allowing us to do more with this lower level of activity.

We are position to continue to growth under these conditions. We benefit from a very shallow or nearly flat production decline profile. Additionally, we have a large inventory of low risk drilling locations that can be developed at very low finding costs. These low cost allow us to spend relatively few dollars to replace and grow production. Accordingly, we project to grow both production and reserves in 2009.

Although, our borrowing base has been reduced, which Bill will cover in more detail, we still have an adequate cushion of liquidity above our current and expected debt levels to sustain our activities until such time as market conditions improve. We expect our operating margins and liquidity to benefit significantly from our hedge position in 2009 and 2010.

I will now ask Bill to review the result of our recent borrowing base determination and its impact on our current financial position. I know this is at the top of your interest list. I will then review our 2008 operational results, before Bill closes with the review of our 2008 financial results.

Bill Rankin

Thanks Darby and good morning everyone. We decided to undertake our borrowing base determination early, so that we would have a clear picture of our capital availability and because we thought the banks price tax were much more likely to go down in the short term rather than up. I think this has proven to be a good decision.

Our borrowing base has been reset at $140 million, 22% below the $180 million borrowing base that was reaffirmed just last October; primarily, the result of a significant decrease in gas price assumptions and to a lesser extent due to downward reserve revisions in our Gurnee fields.

In addition, our borrowings cost under our bank credit facility were significantly below the pricing for new loans in the current markets, so we increased the price in our facility also. The new pricing essentially increased our borrowing cost by 100 basis points across to grid and increased a fee on the undrawn portion of our borrowing base by 12.5 basis points.

There are no other material changes in the agreement. Even with this increase in loan pricing, we continue to be borrowing at historically low rate. Under our current flexible operating, our borrowing base were $140 million, provides a liquidity question of $15 million to $25 million above our expected debt levels. I will be glad to answer any questions at the end of the call.

At this point, I am going to turn the call back to Darby.

Darby Sere

As we have previously reported, at December 31, 2008, our proved gas reserves as estimated by DeGolyer and MacNaughton, independent petroleum engineers, totaled approximately 320 Bcf, a decrease of 8.6% from year end 2007. Proved reserve estimates for the current year, were calculated using an SEC price of $5.84 per Mcf, as compared to $7.58 per Mcf at the end of last year.

The company replaced approximately 300% of its production in 2008, before downward reserve revisions totaling approximately 42 Bcf and a property conveyance of approximately 2 Bcf. Approximately, 13 Bcf of the downward revisions, resulted from the lower natural gas price.

Of the remaining revision, approximately 14 Bcf were attributable to the performance of producing wells in certain sections of our Gurnee field. These revisions lower the average recovery factor of the proved producing reserves in the field. That lower recovery factor was applied to prove behind pipe and undeveloped reserves in the field, which resulted in additional downward revisions of approximately 11 Bcf.

Approximately, 57% of our year end 2008 proved reserves are in the Gurnee field in Alabama and 41% are in the Pond Creek and Lasher fields in West Virginia. Largely reflecting the lack of an alleges coalbed methane production in the area, a conservative initial proved reserve estimate of approximately 4 Bcf, net to our 50% interest, was booked in the Peace River project in Canada. Peace River is the first commercial coalbed methane project in the province of British Columbia.

DeGolyer and MacNaughton also assigned probable reserves of approximately, 22 net Bcf attributable to 39 locations, including the eight initial producing wells. In our Garden City Chattanooga Shale prospect, approximately 2 Bcf of initial proved reserves were signed to five wells. The Garden City prospect is the first commercial Chattanooga Shale production in the state of Alabama. As a result, no under locations were signed, approved or probable reserves.

In addition to the 177 net proved undeveloped locations in our year end 2008 reserve report, DeGolyer and MacNaughton also assigned 177 net probable reserves, to a total of 369 net additional drilling locations in the U.S. and Canada. Net gas sales volumes for the company in the fourth quarter of 2008 were 20.7 million cubic feet a day, a 3% increase compared to the fourth quarter of 2007 and a 5% increase over the third quarter of 2008.

For the year, net gas sales volumes averaged 20.4 million cubic feet a day, a 4% increase compared to the prior year. The increases in net gas sales volumes in the fourth quarter and full year of 2008, over the fourth quarter and full year of 2007, were both 8% in volumes from an overriding royalty interest that was sold effective July 1, 2008 or excluded.

The net gas sales volumes for the company are currently running at just over 21 million cubic feet a day. In our Pond Creek field, net gas sales volumes averaged approximately 14.1 million cubic feet a day for the fourth quarter of 2008, up 11% from the fourth quarter of 2007 and up 4% from the third quarter of 2008.

For the year, net gas sales volumes for Pond Creek averaged approximately 13.7 million cubic feet a day up 11% from the prior year. A total of 240 net wells were producing at the end of 2008. Current net gas sales volumes at Pond Creek are running approximately 14.4 million cubic feet a day.

All matters related to the pipeline dispute with CNX gas have now been resolved and our right to transport our gas to market is now secure. We have recently concluded an agreement with subsidiaries of CONSOL Energy that will allow us to drill 20 wells in Virginia this year. We are focused on reaching a global settlement of all disputes between GeoMet and CNX gas and CONSOL Energy.

In the Gurney field and the Cahaba Basin, our net gas sales volumes averaged 6.2 million cubic feet a day in the fourth quarter of 2008, down 2% from the fourth quarter of 2007 and up 3% from the third quarter of 2008.

For the year, net gas sales volumes from the Gurney field averaged about 6.1 million cubic feet a day, basically flat compared to 2007. A total of 246 net wells were producing at the end of 2008. Current net gas sales volumes at Gurney are running around 6.3 million cubic feet a day.

We hold a lease covering approximately 17,000 acres in our Lasher field located approximately 10 miles north of the Pond Creek field. We drilled 15 wells in Lasher in 2008 and connected 18 wells to sales in October. The Lasher wells are still early in the dewatering process.

We commenced gas deliveries from our Peace River field in Northeast British Columbia on December 31, 2008. We operate this project, which covers approximately 50,000 gross acres of Crown tenure or rights to earn leases and own a 50% work in interest. We have drilled oil production wells and are currently producing from eight wells. The gas in place per 640 acres at Peace River is the highest in any of our projects. Like Lasher, the Peace River wells are in the early stages of the dewatering process.

In our Garden City Chattanooga Shale prospect, we have drilled eight core holes and six production wells including two horizontal wells as of year end 2008. Three of these wells were connected to sales in September.

Our second horizontal well was recently fraced and placed on production. It is currently recovering the frac fluid and is starting to make gas. We are encouraged by our results today in this prospect. A key component to the development of this prospect is the identification of our water disposal solution, which will be our focus in 2009.

At this time, I will turn the call back over to Bill to discuss our financial results.

Bill Rankin

Long term bank debt was $117 million at year end 2008 and is currently $119 million, leaving our liquidity question based on our new borrowing base for $21 million. The bank and capital markets remain very tight and uncertain. GeoMet’s existing bank trade agreement does not expire until January 2011, providing a reasonable amount of time for recovery in both credit markets and gas prices, before we have a need to enter the market to put a new facility in place.

We are approaching 2009 at a conservative manner. As Darby stated, we are committed to limiting our capital spending to our internally generated cash flow. We have constructed our budget, so that we are able to refer all this and most productive expenditures, until we have more clarity on prices and cash flows to remainder of 2009. We project net bank debt at year end 2009 to be less than $120 million. Accordingly, the $140 million borrowing base provides liquidity above our projected requirements.

For the quarter ended December 31, 2008, GeoMet reported a net loss of $34.6 million or a loss of $0.89 per fully diluted share. Included in the net loss was a $50.7 million or $1.30 per fully diluted, pre-tax non-cash impairment to the company’s natural gas properties and a $4.2 million or $0.11 per fully diluted share, pre-tax non-cash mark-to-market gain on derivative contracts.

For the quarter ended December 31, 2007, GeoMet reported net income of $1.6 million or $0.04 per fully diluted share, included net income for the quarter ended December 31, 2007, was a $0.8 million or $0.02 per fully diluted share pre-tax non-cash mark-to-market loss on derivate contracts.

For the year-ended December 31, 2008, GeoMet reported a net loss of $22.5 million or a loss of $0.58 per fully diluted share, included in the net loss was a $50.7 million or $1.31 per fully diluted share pre-tax non-cash impairment, to the company’s natural gas properties and a $5 million or $0.13 per fully diluted share, pretax non-cash mark-to-market gain on derivative contracts.

For the year ended December 31, 2007, GeoMet reported net income of $5.2 million or $0.13 per fully diluted share. Included in net income for the year ended December 31, 2007 was a $3 million or $0.08 per fully diluted share, pretax non-cash mark-to-market loss on derivative contracts.

This impairment was a non-cash charge and had no impact on any of our lending covenants, which by the way we remain comfortably in compliance with. If natural gas processes at March 31, 2009 remained below those that existed at December 31, 2008, we expect to record an additional non-cash impairment to our natural gas properties for the quarter then ended.

Adjusted net income for the fourth quarter of 2008 was $1.4 million down from adjusted net income of $2.1 million in the fourth quarter 2007. Adjusted net income for 2008 was $13.1 million, up from adjusted net income of $7 million in 2007. Please look to this morning’s press release for a reconciliation of net income to adjusted net income.

Average natural gas prices adjusted for realized hedging gains and losses were $7.81 per Mcf in the fourth quarter of 2008, as compared to $7.80 in the prior year quarter. Excluding the impact of hedges, the actual natural gas price realized was $7.1 per Mcf in the fourth quarter of 2008 versus $7.7 in the prior year.

For the year, average natural gas prices adjusted for realized hedging gains and losses was $9.10 per Mcf in 2008, as compared to $7.52 per Mcf in 2007. Excluding the impact of hedges, the actual natural gas prices realized was $9.17 per Mcf in 2008 versus $6.97 last year.

The company generally realizes a positive product differential as compared to NYMEX. This positive differential was approximately $0.07 per Mcf for the fourth quarter and $0.16 per Mcf for the full year. Adjusted EBITDA, which excludes unrealized natural gas hedging gains and other non-cash charges, was $7.6 million in the fourth quarter of 2008, equal to the same period last year.

For the year, adjusted EBITDA was $38.8 million, as compared to $26.1 million of adjusted EBITDA for 2007. Transportation costs were $0.27 per Mcf for the quarter, equal to the prior year. Compression costs were $0.42 per Mcf in the fourth quarter versus $36 per Mcf in the 2007 period. In general the increase and per unit compression cost was primarily due to scheduled repairs and maintenance on our compressive.

Adjusted lease operating expense were $1.98 per Mcf for the fourth quarter, up from $1.78 in the same quarter of 2007. This increase is largely the result of lower processing and disposal of third party produced water and as a result, lower fee income associated with it.

G&A expenses were $1.9 million in the current quarter as compared to $2.3 million in the prior year. As our litigation begins to wind down and as we see the impact of our cost reduction efforts, we expect to see the reduction in future G&A charges.

Depletion rate for oil and gas properties was $1.55 per Mcf for the fourth quarter versus $1.26 per Mcf for the fourth quarter of 2007, reflecting both the transfer of $40 million and unevaluated cost into our depletion base and the downward reserve revision that we discussed earlier.

We have realized just over $2.7 million in cash hedging gains in the first quarter of this year. In addition we have hedged approximately 70% of our estimate gas sales volumes over the last three quarters of 2009, using a combination of three-way collars and swaps.

Also approximately 25% of estimate sales volumes for the first ten months for 2010 are hedged in three-way collars. Details of this hedge positions are include in our press release, these hedges should provide substantial operating margin and liquidity support in 2009.

Since year end 2000, we have grown reserves from 20 Bcf to 320 Bcf, almost exclusively through drilling internally generating prospects. Our three year average finding costs increased in 2008 to $2.38 per Mcf. Looking at this metric over a longer timeframe, so the cost in net reserve in provisions are more probably matched, our finding costs for five and eight year periods are $1.32 per Mcf and $1.13 per Mcf respectively.

In January, we announced the capital budget for 2009 of approximately $24 million. If current low gas prices persist, we will need to reduce our capital spending further to stay within cash flow and restrain growth and debt. Based on our present gas price expectations, we expect to spend less than $24 million on capital projects in 2009. At the same time, we also provided guidance for gas sales volume growth of 10% in 2009.

Production growth estimates could be impacted by changes in our capital plan. This had a relationship between capital spending and production growth. Together with both the uncertainty in volatility of commodity markets and credit markets makes it more difficult than normal to project future events.

Therefore, while we believe the previously issued sales growth and guidance for 10% is reasonably achievable and we are not revising it at this time, it may hopefully need to be adjusted downward. With that we’ll turn the call back over to the operator to arrange for any questions.

Question-and-Answer Session

Operator

Your first question comes from Kevin Smith - Raymond James.

Kevin Smith - Raymond James

I’ve got a few questions; talking about cutting back spending and I think also that’s a wise move, do you having a feel for what maintenance CapEx is. What you really need to spend in ’09 to key production flat?

Bill Rankin

Well, I would guess that based upon what we’re doing that we could look at a finding cost in 2009, of probably something in the range between what we quoted, the $1.13 for the eight year average and the $1.38 for the five year average and we’re probably going to produce about somewhere between 8 Bcf and 8.5 Bcf. So, that would tell you that, we probably are spending a little more than $10 million to be able to replace our production during the year.

Kevin Smith - Raymond James

What’s your base decline range right now? I mean are you still seeing just low production increases from your coalbed methane properties?

Darby Sere

Would you repeat that, Kevin?

Kevin Smith - Raymond James

Yes, what do you think your base decline rate is, through asset base?

Bill Rankin

It’s very low. Probably in the Pond Creek field which is our biggest producing field, it probably is flat to maybe actually a slight incline. In common it’s probably declining at a rate between 5% and 10% if that rate is becoming more shallow at this point and of course in the field, there’s just really not very much production in those new projects. So overall I would guess that our decline rate is probably something less than maybe in the 5% range or something like that.

Kevin Smith - Raymond James

I guess one of the incremental projects, if you decide to rent down CapEx will be at your Chattanooga Shale, John is that fair?

John Gibson

Well, I think that probably the focus on drilling this year will probably initially be mainly in Pond Creek, because that’s where we think we have the opportunities to achieve the highest rates of return and the best growth in production.

Then to the extent that we have additional availability under our projected cash flows, we’ll expand out from there, but those decisions that we’re going to have to make as we go, because we essentially create a flexible capital spending program, so that we can flex it up or flex it down depending our oil prices go, so we end up at a predetermine level at the end of the year and that’s our primary goals; is to end up at that predetermined level and we think that’s important in this environment.

We would like to particularly move forward in the Chattanooga play; we would like to particularly move forward on the Canadian play, but we may not have the capital to do much of that this year. We will probably focus in Chattanooga initially on being sure we have the produced water solution and we also as probably most people in the industry are looking to try to range for co-ventures that might allow us to move forward on some of this drilling and not have to delay it, without having to put additional capital on it.

Kevin Smith - Raymond James

Okay, I have one more question and I’ll probably just jump back in the line. You said you settled a lot of issues with CNX gas and the Pond Creek field, so that’s completely done with; what other issue are lingering?

Darby Sere

Well there is a number of issues that we have been fighting with them on. I guess the most significant issue that we have is we still have our Annie Trust suit going against them. They are still blocking permits to drill wells in Virginia, although we did get a 20 well agreement with them in January and early February. But basically we want to get everything results, so that we can both get about our operations in the area and not have to be spending money and time in court.

Kevin Smith - Raymond James

Are you’ll disclosing I guess how to settle the Pond Creek issues?

Darby Sere

Well, I mean that the biggest settlement was the Supreme Court Verdict. That result, the biggest issue we had going with them. There was another minor settlement related to the pipeline and we’re not disclosing any terms, but there were no significant terms that affected the company. We didn’t eliminate any remaining potential risk to the pipeline.

Kevin Smith - Raymond James

Okay and we’re not going to see any sort of cash settlements go up in Q1 or anything like that?

Darby Sere

Well, I don’t expect to see any cash settlements to go out the door.

Operator

(Operator Instructions) Your next question comes from Phil McPherson - Global Hunter Securities.

Phil McPherson - Global Hunter Securities

A couple of kind of quick questions; when you do these three-way hedging, I’m just trying to figure out what you’re going to average for your prices right now and maybe you can give us a little bit of what you’re receiving in the field right now and then how it works through? When it bursts through that bottom portion you sold, does it make the gain you got on the topside or can you kind of walks us through that?

Bill Rankin

Well, in terms of what we’re receiving in the field right now, I think for the year-to-date we’re receiving something like $0.16, $0.17 premium over NYMEX. It’s kind of what we’ve been realizing year-to-date in the field. That’s across the company. It’s a little higher in West Virginia, a little lower in Alabama, but that’s pretty close.

In terms of the way the three-ways work. One of the things we put in the press release is what we call the put spread, and if you really look at that the put-spread is a benefit we will receive over the current gas price. If the current gas price is $4 for the summer and we have a three-way collar in place, then the put-spread I think in the summer is $2.13. So at $4 gas price, we will realize a net price of $6.13, the $4 price plus the put-spread. So, if you really focus on those put-spreads, extra benefit we receive over the current price.

Phil McPherson - Global Hunter Securities

And then you get the $0.16 or whatever, top…?

Bill Rankin

Top of that; exactly.

Phil McPherson – Global Hunter Securities

Okay, great. So, if we average $4 for the summer, then you’re getting like 6.25’ish, a kind of a number to kind of use or some in that nature?

Bill Rankin

For the hedge volumes

Phil McPherson – Global Hunter Securities

For the hedge volume, yes and what kind of gas price are you getting for your Canadian gas right now?

Bill Rankin

I think we’re getting maybe $0.50 under NYMEX, something like that. I think that’s net after transportation. So, in winter months you actually typically get a premium up there and then in the summary you get some kind of a discount, but I think at year end we were getting 571 or 584 in the U.S.; I think we were getting like 543 in Canada if I’ve not mistaken. So, at that point in time it maybe a differential, but about minus $0.40.

Phil McPherson – Global Hunter Securities

Okay, great and on the Piece River, do you have a like a total CapEx number you’ve spent in that project up to this point, to kind a get of handle on what that’s going to eventually look like up there?

Bill Rankin

Up to this point I would guess we spent between $25 million and $30 million.

Darby Sere

$27 million.

Bill Rankin

$27 million

Phil McPherson – Global Hunter Securities

Alright and on the Garden City, what have you kind of spent down there?

Bill Rankin

Probably something in the range of around $10 million to $12 million. I think we transferred about $40 million of costs at year end from unevaluated properties and that was almost totally related to Peace River and Garden City. We essentially have nothing left in unevaluated properties. So, we transferred all of those cost associated with getting those projects going at a time that we transferred in very few reserves. So, when you put that together, with the fact that we had a negative revision, that’s why the finding cost numbers went up for this year.

Phil McPherson – Global Hunter Securities

When you guys talked about the negative revisions with the Gurnee field, which has been something that’s been a year-over-year kind of thing; and I understand from our past talks, it was the rate of the water and I know you were doing some pumps and stuff, but what I want to really get to is, how much more of the reserves on the book are risk per say in this project and have we finally kind of cleared the deck on it?

Darby Sere

Well, I think Phil, the key issue in Gurnee is that we are expecting these wells to incline and in the better areas of the field, the DeGolyer and MacNaughton still expects those wells to incline in their reserved report. So, as we get further and further into this project, if we don’t see these wells in the better areas of the field starting to incline, we could have some additional revisions.

I think probably last year we saw maybe six wells inclining; recently we saw several more starting in incline. So, I think that we will see these wells incline and avoid any of the significant revisions like we experienced this year, but if they don’t occur by the end of ’09, there will be some additional revisions.

Now, I will point out to you, that our banks, in calculating our borrowing base, they looked at a case where the future inclines were eliminated from the projections. So that the wells performed in the manner they are performing now and were declining at a very slow rate of a low period of time, and we still achieved the borrowing base of the $140 million.

So clearly, we have a significant amount of proved reserves in the Gurnee field, whether these wells incline or not, but the value of those reserves and the absolute quantity is still subject to some risk if we don’t see those inclines.

I think it would be fair to say that in the less productive areas of the field that we’ve talked about in the past, that’s pretty much all been cleared out at this point in time. The combination of the lower prices in D&M’s report pretty well cleared out any exposure we had in the less productive areas of the field.

Operator

Your next question comes from Mark Lear - Sidoti & Company.

Mark Lear - Sidoti & Company

Just currently looking at operating expenses, compression and transportation, I saw it tick up a little bit in the quarter. I’m just kind of thinking about how related to the CNX dispute, should we be looking for those at least on the transportation side, expenses to go down a little bit or are those already kind of factored into what you were paying previously?

Bill Rankin

Well the transportation expenses are really tied; they’ve actually comedown quite a bit in general from 2007 previously, because of getting our new pipeline in place and not having to move our gas through the current safe line anymore.

The fluctuations from quarter-to-quarter right now really relate to, we have some firm capacity on the Columbia System where we used to take our gas and in certain times of the year we can release that capacity and some times of the year we can’t. So, our ability to release that capacity makes that transportation cost move up and down a little bit.

We’re looking for opportunities to lay off that capacity in total or release most of it. We still need some of it for our Lasher field and if we did that that would kind of level out those transportation costs at a level lower than what we had in the fourth quarter. I don’t see it going any higher than what they were in the fourth quarter and I think there is real potential that they can comedown from that level.

Mark Lear - Sidoti & Company

Then I guess what about on the operating?

Bill Rankin

On the operating; the many side that affected operating cost is we have a offset operator in one of fields where we move a lot of the water form and we get disposal fees and those disposal fees have comedown because they’ve had some problems of sales, and that probably had more impact on the quarter than anytime.

The other thing that impacted the quarter is we put three new projects online late in the year and when a projects first comes on, the type of coalbed methane projects we do, the initial operating costs until you get the field up and running are very high and some of these fields initially might be $6 an Mcf. Now they are not going to be that, but for a very short period time. So, the quarter was also effected by the startup of these new projects.

I would think that our operating costs are going to trend back to what maybe the prior year numbers were and we’re working very hard to reduce cost everywhere in the corporation, capital costs, operating costs, G&A costs and we’re certainly starting to see some significant changes in the service level costs and services companies.

So, we’re hopeful that operating costs will actually comedown in 2009 versus 2008. We’re not currently projecting that, but we think there’s a good change we can achieve that.

Mark Lear - Sidoti & Company

I guess then, you may have mentioned that moving water for another operator, are you referencing CDX?

Darby Sere

I am referencing CDX.

Mark Lear - Sidoti & Company

Data’s there kind of issues, kind of impact how you’re looking at Gurney going forward and you mentioned maybe testing other parts of the field. I’d imagine just in the pricing environment that’s been curtail, but I guess kind of looking at that project going forward and not haven’t someone splitting the cost there with you?

Darby Sere

Yes, we are certainly deferring any activity in the west side of the Gurney or the Cahaba River in the Gurney field this year. Its certainly a victim of allocating capital to the best and lowest risk and highest return projects, but clearly it also is related to the fact that we have to have an offset operator that can share those costs and so we are awaiting the resolution of CDX’s ownership in those properties before we move forward on the west side of that Cahaba River.

Mark Lear - Sidoti & Company

Just to touch on the share project, I guess maybe just kind of discuss what the technical aspects of drilling there are. You mentioned you fact a well; how long of lateral length and maybe what we can expect from initial production rates or EUR’s and those kinds of stats, you got them?

Darby Sere

Well, it’s really early. On the well that we just fract, it’s making a little bit of gas and it’s been making over 200 barrels of water a day and the frac fluid is about 65%, 75% recovered.

So, we’re going to see what this well does in the near future, but we did drill it out 2,200 feet as compared to only 1,400 feet on the first horizontal well. We drilled it in a perpendicular direction to the first horizontal well. So, we’re hoping to see much better rates on the second wells than the first well, so we’re not there yet.

On the first well, we have seen rates as high as 250 Mcf a day, but we’re also having significant problems keeping the pumping unit working, because of sand flowing back into the well bore and clogging the pump. So, we have not had a good long term test on the first well.

The areas that we’ve drilled the two verticals and the two horizontal wells is on the East side of the prospect in Blount County and on this side of the prospect, it does appear that horizontal drilling is going to be the way to develop the field.

Again, until we figure out how to deal with the produced water, we’re really going to mainly evaluate the production results from these four wells and try to define a produced water disposal solution, but the gas rates here are encouraging and we think we can make money here; we’ve got to be able to dispose of the water.

Operator

Your next question comes from Kevin Smith - Raymond James.

Kevin Smith - Raymond James

Are you guys participating in the Moosebar Shale play at Peace Rive?

Darby Sere

No, we are not Kevin. We formed that opportunity out to our partner, Canada Energy Partners and I’m not sure whether that well has been drilled or not, but we did decline to participate, we choose to format instead.

We do have an opportunity, at various points during the development of that shale, if it does occur, to comeback as a working interest owner, both as a participating owner and as a back end owner and we have retained an overriding royalty interest. So we’re pulling for them, but we didn’t think it was a wise use of our capital.

Operator

At this time, there are no further questions. I would now like to turn the call over to Mr. Smith for any closing remarks.

Steve Smith

Well, we just want to thank everybody for joining us today. We’ll all be in the office if you have any further questions and this will conclude today’s call.

Operator

This concludes today’s GeoMet, fourth quarter and fiscal 2008 results of operations and financial condition conference call. You may now disconnect.

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Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

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Source: GeoMet Inc. Q4 2008 Earnings Call Transcript
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