Executives
Tony Oviedo – Vice President and Chief Accounting Officer
Darby Sere – Chairman, President and Chief Executive Officer
William C. Rankin – Executive Vice President and Chief Financial Officer
Phil Malone – Senior Vice President of Exploration
Bret Camp – Senior Vice President of Operations
John Gibson – Vice President of Corporate Development and Marketing
Steve Smith – Treasurer
Analysts
Kim Pacanovsky – Collins Stewart.
Phil McPherson – Global Hunter Securities
Mark Lear – Sidoti & Co
Kevin Smith – Raymond James
J. McRae – Next Generation Equity Research
GeoMet Inc. (GMET) Q3 2008 Earnings Call November 10, 2008 11:30 AM ET
Operator
(Operator Instructions) I will now turn the call over to Steve Smith, Treasurer of GeoMet Resources.
Steve Smith
Earlier today GeoMet issued a press release announcing our third quarter financial and operating results. If you need a copy of the release one is available on our website at geometinc.com. Today you'll be hearing from Darby Sere GeoMet's Chairman, President and Chief Executive Officer, and Bill Rankin our Executive Vice President and Chief Financial Officer. Also present today are Phil Malone Senior Vice President of Exploration, Bret Camp Senior Vice President of Operations, Tony Oviedo Vice President and Chief Accounting Officer and John Gibson Vice President of Corporate Development and Marketing. After remarks from Darby and Bill we will have a question and answer session.
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 discussion of the risks and uncertainties which could cause actual results to differ from those contained in the forward-looking statements, see forward-looking statements and risk factors in the company's filings with the Securities and Exchange Commission.
The terms lease operating expenses, adjusted EBITDA and adjusted net income are non-GAAP measures. Please refer to our website or this morning's press release for a reconciliation of these non-GAAP measures to GAAP measures. I'll now turn the call over to Darby.
Darby Sere
As we announced today GeoMet reported another quarter of solid operating and financial performance and the fundamentals of our business remain strong. The reaffirmation of our $180 million borrowing base provides us with significant liquidity to weather the uncertain times facing our industry. We will, however, pullback on 2009 capital spending plans until we have more clarity as to what the commodity and financial markets may be like next year.
GeoMet enjoys a long life shallow decline reserve base and low fining and development costs. Consequently, we expect to grow production and reserves through the reinvestment of our operating cash flow and limited borrowings under our credit facility. We will preserve our strong liquidity position. However, if performance exceeds expectations or economic conditions improve, we will be prepared to utilize our liquidity to ramp up capital spending and accelerate growth.
First, let me comment on our victory in the pipeline right away dispute with CNX Gas. As we expected, on September 12 the Virginia Supreme Court reversed the order issued in May 2007 by the Circuit Court of Buchanan County. In its unanimous decision, the Virginia Supreme Court held that the lease between CNX and Pocahontas Mining Company did not grant CNX an exclusive right to transport gas across PMC's property.
This ruling removed a cloud that had been hanging over the company for over two years. Although the transportation and marketing of our gas was never interrupted during this litigation, it was a tremendous distraction in terms of time and resources. The ruling will now allow us to pursue opportunities to maximize our pipeline's value even through the transportation of third party gas volumes for a fee or through a monetization transaction.
Average net gas sales volumes for the quarter were 19.8 million cubic feet per day a 1% increase from the same period in 2007. Had the net gas sales volumes in the third quarter of 2007 not included 0.9 million cubic feet per day from an overriding royalty interest that was assigned effective July 1, 2008, the comparable year-over-year increase in net gas sales volumes would have been 6%. Net gas sales volumes for the company are currently running at approximately 21 million cubic feet per day and we expect to grow sales volumes through the remainder of the year.
In our Pond Creek field, net gas sales volumes averaged approximately 13.6 million cubic feet a day for the quarter up 9% for the same period last year and up 1% compared to the second quarter of this year. We recently added 13 new wells to sales and expect to add an additional 12 wells to sales by yearend. Net gas sales volumes for Pond Creek are currently running in excess of 14 million cubic feet per day. This is a high quality high return project with over 250 development drilling opportunities ahead of us. We expect gas sales volumes from this field to continue to increase for many years to come.
At our Lasher field, the metering facilities at the Columbia interstate pipeline are finally in service and we commenced gas sales from 15 wells on October 28. We expect to connect three more wells this month. After less than two weeks of production, net gas sales volumes from Lasher are running at approximately 200 Mcf a day and we expect volumes to increase as these wells dewater.
In the Gurney field, our net gas sales volumes averaged 6.1 million cubic feet per day for the third quarter. Current net gas sales volumes from Gurney are running slightly higher. During the third quarter four new wells were added to sales and we plan to add an additional seven new wells before yearend. Production has generally been flat over the past two years during which time drilling has been limited.
For this trend in production to improve one or more of the following will need to occur. One, more wells begin to demonstrate an inclining production profile. Two, increase gas production from current high water production wells, or three we commence development on the west side of the Cahaba River.
At our Peace River project in British Columbia, we have drilled and completed five wells in 2008. The installation of facilities is continuing and we expect to commence gas sales from eight wells during December. These eight wells were drilled on approximately 90-acre spacing with gas in place ranging from 3.4 to 5.5 BCF per well.
Based on production testing of the wells drilled prior to this year, we expect first year well per well production rates to be in the range of 50 to 100 Mcf a day inclining over four to five years to peak rates in the range of 300 to 400 Mcf a day. We should book initial prove reserves in this project at year end 2008.
Due to the lack of historical analogs in the area, initial recovery factors will be conservative likely less than 50% of gas in place. There is a CBM project immediately north of us that has been in the testing phase. Shell Canada has recently acquired an operating interest in this project by committing to spend $50 million to earn a 75% interest in the project. We understand that they expect to commence gas sales from that project in 2009.
Our Chattanooga shale prospect, which we refer to as Garden City, is actually geologically divided by an anticline creating two geographic areas with slightly different characteristics. On the southeast side of the anticline we have drilled two vertical wells and one horizontal well. The vertical wells were refracted in July and the horizontal well was fracted in August. The horizontal well has produced at initial rates ranging from 100 to 200 Mcf a day from a relatively short 1,500 foot lateral. We are experiencing pump problems due to frac sand flowing back into the well board. This results in shut-ins to replace pumps and allows water to accumulate in the lateral section of the well bore thereby impeding gas production.
As a further result, the frac load of approximately 15,000 barrels of water has not yet been fully recovered. Once these issues are resolved we expect to see higher gas production rates from this well. All three wells have been connected to a nearby sales line and when the horizontal well is pumping gas sales have been as high as 265 Mcf a day. We are currently drilling a second horizontal well in a direction perpendicular to the first well with a planned lateral of 2,200 feet.
On the northwest side of the anticline, the shale thickness and gas production potential are greater, but the two vertical wells drilled there have tested higher water production rates. The initial vertical well was producing gas at a rate of 175 Mcf a day and still increasing when it was shut-in. The second well was tested for a short time without producing gas before it was shut-in due to high water production rates.
Finding a water disposal solution will be necessary for the development of either area of this prospect. We are currently drilling a deeper well to identify other gas producing zones or alternatively water disposal zones below the Chattanooga shale. At this time I will turn the call over to Bill to discuss our financial results.
William Rankin
GeoMet's balance sheet is strong. It has access to significant liquidity through its credit facility and its bank group remains engaged and supportive. Bank debt net of cash totaled $106 million at the end of the third quarter, 31% of total capitalization and only $0.30 per Mcf approved reserved. The borrowing base under our bank credit facility has been reaffirmed of $180 million. We have more than $70 million of unused capacity under this agreement at the end of the quarter. We expect the borrowings under our credit facility to be less than 70% of the borrowing base through the end of 2009.
The company reported net income of $17.5 million in the quarter as compared to income of $1.6 million for the third quarter of 2007. Each of these quarterly periods was impacted by unrealized hedging gains resulting from the mark-to-market of our natural gas hedge position. In the third quarter of this year we recorded an unrealized after tax hedging gain of $13.4 million as compared to an unrealized after tax hedging gain in the amount of $0.4 million in the same period last year.
Excluding the impact of unrealized hedging gains, adjusted net income was $4.1 million in the third quarter of 2008 compared to adjusted net income of $1.2 million in the third quarter last year. For the nine months of 2008, adjusted net income totaled $11.7 million as compared to $5 million in the same period last year. Please refer to today's press release for a reconciliation of this non-GAAP measure.
Average natural gas prices adjusted to realize hedging gains and losses increased to $9.49 per Mcf in the current quarter compared to $6.95 per Mcf in the prior year period. Excluding the impact of hedges, the actual natural gas price received was $10.26 per Mcf this quarter compared to $6.26 per Mcf last year.
Adjusted EBITDA, which excludes unrealized hedging gains or losses and other non-cash charges, was $10.3 million for the quarter compared to $5.6 million in the same period last year and $11.5 million in the second quarter. Adjusted EBITDA for the first nine months of 2008 totaled $31.2 million as compared to $18.5 million in the prior year period. Please refer to this morning's release for the reconciliation of this non-GAAP measure.
Transportation costs were $0.17 per Mcf for the quarter compared to $0.30 per Mcf in the same period last year and $0.14 per Mcf in the second quarter of this year. Unit transportation costs may vary from period to period as new projects come online and relative to our ability or inability to layoff excess for transportation capacity.
Depression costs were $0.45 per Mcf for the quarter versus $0.35 per Mcf in the same period in 2007 and $0.40 per Mcf in the second quarter of this year. The incremental unit rate for depression costs reflects scheduled maintenance at our Pond Creek field. Adjusted lease operating expense, which nets a certain saltwater disposal revenues, was $1.83 per Mcf for the quarter compared to $1.78 per Mcf in the same period of 2007 and $1.85 for Mcf in the second quarter of 2008. Please refer to this morning's press release for a reconciliation of this non-GAAP measure.
G&A expense was $2.1 million in the current quarter as compared to $2.5 million in the same period last year, and $2.9 million in the second quarter this year. Reduction in professional fees was a major component of this decline. We expect these expenses to continue to moderate from recent levels now that the pipeline litigation has been resolved and as our public company transitional costs continue to decline.
Depletion rate for gas properties is $1.31 per Mcf for the quarter [inaudible] the above prior quarter. Our capital spending for 2008 is now expected to total $56 million. We are in the process of finalizing our 2009 operating capital budget. We expect capital spending in 2009 to be lower than previously suggested and lower than the current year levels.
We believe the current level of uncertainty in the financial and commodity markets dictates a cautious strategy. Preliminarily, we anticipate 2009 capital spending in the range of approximately $40 million and year-over-year production growth in excess of 10%.
As the planning process is completed we will provide more definitive guidance. We are revising our guidance for gas sales volume growth in 2008 down to approximately 5% year-over-year. Further delays and commencement of sales of last year in Peace River contributed to this revision.
Last year commenced sales on October 28 and Peace River is expected to go online before yearend. Therefore, we have some built in production growth going into 2009. We believe GeoMet is well positioned to deal with the current environment of lower prices and reduced access to capital.
First, we have a long lined, shallow decline reserve base coupled with very low comparative finding and development costs. This results in low asset intensity and based upon historical performance, less than one-third of our operating cash flow is needed to replace reserves.
Second, we do not have steep production declines to overcome as do many in the industry. Therefore, free cash flow should be adequate to grow both production and reserves even during periods of reduced capital budgets. Most of our reserves are proved developed, so the capital we spend adds both production and reserves not just production. Our reserves are strategically located yield a positive differentials to [inaudible], an average of $0.20 per Mcf for the first nine months of this year.
This geographic advantage will become increasingly important if basis differentials continue to widen as gas supplies remain plentiful. We have no scheduled bank debt maturities for over two years. We are comfortably in compliance with all of our debt covenants and the banks in our groups are solid and supportive.
We have a hedged position that cushions our downside considerably over the next 18 months. Approximately half of our sales volumes through October of next year are hedged with [inaudible] averaging $7.96 per MMBtu, and approximately one-quarter of our sales volumes thereafter through March 2010 are hedged with lower than $9.50 per MMBtu.
With that I'll turn the call back over to the operator to arrange for any questions.
Question-and-Answer Session
Operator
(Operator Instructions). Your first question comes from Kim Pacanovsky – Collins Stewart.
Kim Pacanovsky – Collins Stewart
Can you tell me what the production you would expect to get out of Gurney is over the next year?
Darby Sere
Well, I don't know that it's going to be a whole lot different from what we're seeing today, unless one of those three things start happening. Now we don't plan to develop the west side of the Cahaba River as yet because our offset operator is in a sales process, and we plan to defer development over there until we see what happens with his interest.
Kim Pacanovsky – Collins Stewart
Okay so then on the east side how many wells will be drilled in '09?
Darby Sere
Just the number of wells required to maintain our lease which is probably in the neighborhood of five.
Kim Pacanovsky – Collins Stewart
Okay.
William Rankin
So we're projecting production in Cahaba to be relatively flat next year maybe a slight increase again with very limited drilling.
Kim Pacanovsky – Collins Stewart
Okay, and could you just update us on some of the other issues that you've been having with CNX?
Darby Sere
Basically, we have been blocked from drilling wells in Virginia, and so we are still fighting their ability to do that, and we have our anti-trust suit against them in Tazewell County.
Kim Pacanovsky – Collins Stewart
And what's the status of that?
William Rankin
We have a hearing on December 17, on the [inaudible] that they have filed and we fully expect that we will be successful in that hearing and that that will go onto trial.
Kim Pacanovsky – Collins Stewart
Okay, and just some guidance on the cost side for 2009, can you just give us an idea of what to expect for LOE?
William Rankin
I think LOE costs should be, they may be a little higher on a per unit basis in 2009 than they are in 2008 because we've got a couple of new projects going on stream and typically early in a new project the LOE costs are higher and then starts to decline, but as to concrete and high dollar, I really don't expect much change in unit cost from year-to-year. But the overall corporate costs may be slightly higher due to the new project.
Kim Pacanovsky – Collins Stewart
Okay and then final question, in Peace River, what do you anticipate to book per well?
Darby Sere
Well I think we kind of gave you a range, and that's basically all we can...
Kim Pacanovsky – Collins Stewart
Okay I must have missed that, I'm sorry. Can you repeat it?
Darby Sere
I can repeat it if you'd like. The eight wells that we put on, are going to put on stream have gas in place ranging from 3.4 to 5.5 BCF per well.
Kim Pacanovsky – Collins Stewart
Okay.
Darby Sere
And we expect the recovery factor in the first year to be likely less than 50% of gas in place.
Operator
Your next question comes from Phil McPherson – Global Hunter Securities.
Phil McPherson – Global Hunter Securities
Bill, you said you expected the debt balance, I thought you said '09 but I think you might have meant '08 to be 70% of the base?
William Rankin
No actually what I said was that right now we think that if the borrowing base stays where it is and we move forward the way we planned to, we would expect it even by the end of 2009, we would be no higher than 70% utilization on our borrowing base. One of the things we're trying to do Phil, in this period of uncertainty is be sure we have a significant cushion available under our borrowing base just to provide liquidity protection for uncertainty.
Phil McPherson – Global Hunter Securities
Okay great, I just wanted to make sure I understood that.
William C. Rankin
Yes, we're well below 70% now so we would expect it to go up a little bit between now and the end of 2009, but even without an increase in the borrowing base, to be no more than 70%, and that's kind of the target we're using to manage our operations.
Phil McPherson – Global Hunter Securities
Would you use a hard number for '09 G&A of about $10 million, does that kind of seem right?
William Rankin
You know, I think there's a good chance that the number could be lower than that, I don't think I would use a number higher than that. I think we would expect that as the year goes on, that we'll continue to see G&A costs drop so in a hard number I think $10 million is a reasonable number and I would hope that we could beat that number for 2009.
Phil McPherson – Global Hunter Securities
Great, Darby can you just talk on these horizontals that you're doing in Garden City, you said the first one was 1,500 feet, the second ones going to be 2,200 feet. Was there difficulty in the first one or was that the planned length?
Darby Sere
No, there was. We had planned it for 2,200 feet and we had some drilling difficulty. It was the first horizontal well we had drilled in the prospect, and we could have gone further but we decided to go ahead and see what we could get out of it, 1,400 feet. But both of them were planned for 2,200 feet.
Phil McPherson – Global Hunter Securities
What are your costs on these horizontals now?
Darby Sere
Well, the first one was over $1 million but we did have problems. We have learned a lot, we are expecting this next one to come in at about $1 million, and hopefully we can get them below $1 million if we start developing the prospect in a horizontal fashion.
Phil McPherson – Global Hunter Securities
When would you anticipate being able to give us kind of an EUR number on these, what kind of reserves?
Darby Sere
I think Phil, in the case of shale, we don't really know what to expect in terms of recovery factor. Also, when we drill our core holes all we're measuring in gas content is the gas that's absorbed in the shale. We know that there's a lot more free gas that we can't measure by that measurement tool. So we're not really comfortable about estimating reserves based upon in place numbers. The only way we feel comfortable about estimating reserves is after we see what the wells produce over a period of time, and basing their reserves on actual performance.
So I think it's early to talk reserves in this prospect, although it's possible that we'll book some at yearend and we'll learn what the independent engineers think of it, but from our standpoint, we're not real comfortable talking about reserves per well here yet.
Operator
(Operator instructions). Your next question comes from Kevin Smith – Raymond James.
Kevin Smith – Raymond James
What type of differentials are you seeing at Peace River?
William Rankin
We're not seeing any yet since we're not selling any gas, but I think for all of 2008 the [inaudible] differential, which is where we think we are going to be selling gas, was about -45 or maybe a little less than that, to [inaudible], so most of the basis in the west as you know has widened out. But [inaudible] has not widened out much. So we're going to have to watch basis differentials out there carefully, but right now we're thinking it's probably going to be something less than -$0.50.
Kevin Smith – Raymond James
I guess to build on the last question, you might not be able to answer this but, what sort of IP rate and production rates do you need in the Chattanooga shale to meet internal rate of return hurdles?
William Rankin
At Peace River?
Kevin Smith – Raymond James
No, the Chattanooga shale.
Darby Sere
Garden City?
Kevin Smith – Raymond James
Yes Garden City, I'm sorry.
Darby Sere
Well I think that if we see rates a little bit better than what we've seen in this first horizontal well, which we expect this first horizontal well to do, if we get the pumps pumping continuously, I think will work. I think 250, 350 Mcf a day rate will work just fine.
Operator
At this time there are no further questions. Gentlemen do you have any closing remarks?
William Rankin
Well we just want to thank everybody for joining us and we're available for calls if questions come up later and this concludes today's call.
Operator
Thank you, this concludes today's conference call, you may now disconnect.
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