Steve Smith - Treasurer
Darby Sere - President and CEO
Bill Rankin - EVP and CFO
Brett Camp - SVP Operations
Tony Oviedo - VP and CAO
GeoMet Inc (OTCQB:GMET) Q4 2007 Earnings Call March 17, 2008 11:30 AM ET
Good morning, my name is Brandie, and I will be your conference operator today. At this time, I would like to welcome everyone to the GeoMet, scheduled fourth quarter and fiscal 2007 earnings release conference call. All lines have been placed on mute to prevent any background noise. After the speakers remark there will be a question-and-answer session. (Operator Instructions)
I would now like to turn the call over to Steve Smith, Treasurer. Please go ahead sir.
Thank you, Brandy, and good morning everyone. Earlier today GeoMet issued press release announcing our fourth quarter and fiscal 2007 operating results. If you need a copy of the release, one is available on our web site at 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 presented today are Brett Camp, GeoMet's Senior Vice President of Operations; and Tony Oviedo, our Vice President and Chief Accounting Officer. After remarks from Darby and Bill, we will open the lines for questions.
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 for the Securities and Exchange Commission.
Oil and gas companies are only permitted to disclose proved reserves in their filings with the SEC. Proved reserves are reserves which are demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions.
In today's conference call we will also use the term probable reserves. The term probable reserves, describes reserves that may be potentially recoverable through additional drilling, and they are not allowed to be included in the company's filings with the SEC. A probable reserve estimates by their nature are more speculative than proved reserve estimates. Investor's are urged to closely consider this disclosure together with those in today's press release and our filings with the SEC.
The terms finding and development cost, EBITDA and adjusted EBITDA are non-GAAP measures and may also be used in this conference call. Please refer to our press release this morning for our calculation of finding and development cost and a reconciliation of EBITDA and adjusted EBITDA. I'll now pass the call over to Darby.
Thank you, Steve. Good morning everyone and thank you for joining us today. We are pleased to welcome you to GeoMet's fourth quarter and fiscal year 2007 Earnings Call. As previously announced, our proved reserves at year end 2007, as estimated by DeGolyer & McNaughton, an independent petroleum engineering firm increased 8% to 350.2 Bcf using an SEC price of $7.46 per MMBtu. This represents a reserve replacement of 444% for the year all through the drill bit.
Our proved reserves were 76% developed, approximately 38% of the proved reserves are in the Pond Creek and Lasher fields in the Central Appalachian Basin, with 61% in the Gurnee field in the Cahaba Basin.
Our low finding and development costs combined with our high reserve replacement provide us with significant growth potential. Our three year average finding and development cost was $1.25 per Mcf, while our reserve replacement for the same three year period was 882%. Since year end 2000, we have grown reserves 18 fold primarily through the drill bit from internally generated prospects. On a 12 months trailing basis and assuming the same average finding and development cost, only 34% of our cash flow is required to replace production, leaving 66% available to fund growth.
In addition to proved reserves located in three development projects Pond Creek, Gurnee and Lasher, we have identified approximately 480 net additional unproved drilling locations in these fields at year-end 2007. DeGolyer & McNaughton prepared a report assigning a 189 Bcf of net probable reserves to these additional unproved drilling locations at December 31, 2007.
As previously announced, we planned capital expenditures of $48.8 million in 2008; over 70% of those expenditures are allocated to drilling, completing and connecting 46 low risk CBM development wells. Approximately 10% of those expenditures are allocated to exploratory drilling in our Shale prospect and the remaining 20% is budget for leasehold and other capital costs.
Our decisions to reduce drilling activity in the Pond Creek and Gurnee fields in 2007 and 2008 were made because of the pipeline litigation risk we faced in Virginia in the first half of 2007. To keep our bank debt at acceptable levels, if you allocate capital to our two early stage CBM development projects and our shale exploration prospect and to allow us time to evaluate well treatment techniques on the east side of the Cahaba River in 2007, and production results from new drilling on the west side of the river in 2008.
Net gas sales volumes for the company in the fourth quarter of 2007 were 20.2 million cubic feet a day, a 7% increase compared to the fourth quarter of 2006, and a 3% increase over the third quarter of 2007. For the year, net gas sales volumes averaged 19.5 million cubic feet a day, a 14% increase compared to the prior year. Net gas sales volumes for the company are presently running at approximately 20.6 million cubic feet a day.
In our Pond Creek field, net gas sales volumes averaged approximately 12.7 million cubic feet per day for the fourth quarter of 2007, up 10% from the prior year period, and up 2% from the prior quarter. For the year, net gas sales volumes from Pond Creek averaged approximately 12.3 million cubic feet per day, up 17% from the prior year.
A total of 214 wells were productive at the end of 2007. Current net gas sales volumes at Pond Creek are approximately 13.4 million cubic feet per day. Pond creek is performing in line with our expectations and we plan to drill 21 wells there in 2008.
In the Gurnee field in the Cahaba Basin, our net gas sales volumes averaged 6.4 million cubic feet per day for the fourth quarter of 2007, up 4% from the prior year period, and up 5% from the previous year. For the year, net gas sales volumes from the Gurnee filed averaged approximately 6.1 million cubic feet a day, up 15% from 2006. A total of 234 wells were productive at the end of 2007. Current net gas sales volumes at Gurnee are approximately 6.1 million cubic feet a day.
I would like to clarify the status of our operations in the Gurnee field. Wells drilled today can be grouped into three major categories. In the first category are wells that exhibit relatively flat production including some with slight incline or slight decline, over 70% of the wells in the field are in this category.
In the second category, are wells with high initial water production and little or no gas production, approximately 13% of the wells in the field are in this category, and are located primarily in the southern portion of the field.
In the third category, are wells with low water and low gas production, approximately 16% of the wells are in this category. As to the first category of wells, we believe the gas production from these wells will eventually incline and that the reserves assigned to them, and possibly more, will be recovered overtime. The exact slope and timing of that incline is difficult to predict.
The high water production from wells in the second category is an indication of good permeability. We also have high confidence in the gas in place, as a result of our extensive core hole drilling and gas content data. As the water production declines, we expect these wells to be among the better wells in the field.
As to the third category of wells, we will need to employ a new treatment or recompletion technique to improve performance or face downward revisions to proved reserves overtime. At December 31st, 2007, the proved reserves assigned wells in the third category; represent approximately 7% of our total proved reserves.
We are not yet identified a treatment or recompletion technique that has been consistently successful to apply in a field-wide program, although we'd continue to evaluate new ideas. Average daily gas production per well has remained fairly flat in the Gurnee field. Normally, we would expect this per well average to increase as gas production from the wells in the fields inclines. Therefore, until inclines becomes prevalent, new wells must be drilled for gas production to increase substantively. We reduced drilling activity in the Gurnee field in 2007 and plan to reduce it further in 2008. We currently plan to drill five wells at Gurnee during 2008.
In 2007, we drilled our first two wells on the less geologically complex west side of the Cahaba River, in the southern acreage block, and have recently initiated production testing. Initial results from these wells are encouraging; however, it is purely to retain indefinitive conclusions.
Drivers for increased production from the field may include several sources, new drilling, especially on the west side of the river, if initial positive results continue. The dewatering of the high water production wells or from the commencement of expected production, incline from the wells with relatively flat production.
I would like now to discuss our two early stage development projects, the Lasher field in West Virginia and the Peace River field in British Columbia. We hold approximately 17,000 acres of leases in the Lasher field, which is located approximately 10 miles north of the Pond Creek field. At December 31, 2007 we had drilled four wells at Lasher and we plan to drill 15 additional wells and commence gas sales from the field in the second quarter.
The geologic setting at Lasher is very similar to Pond Creek except that the coal seams are slightly thinner and more shallow. The Lasher field has two significant advantages over Pond Creek, a water disposal well and a major interstate pipeline are both located in our leasehold. We have adequate firm transportation capacity on the pipeline and we have recently entered into a pipeline interconnect agreement.
We believe that lower development costs, resulting from reduced frac cost due to coal thickness, along with the operating efficiencies associated with the close proximity of the water disposal well, will allow us to achieve rate of return at Lasher that are comparable to returns being achieved in the Pond Creek field.
We have a total of a 129 proved and probable un-drilled locations in the Lasher field. It is also important to note that the Lasher field is in no way associated with our Pond Creek litigation. The Peace River field is located in Northeast British Columbia near the community of Hudson's Hope. We operate this project which covers approximately 50,000 acres of Crown tenure or rights to earn leases, and we own a 100% working interest. As of year end, we had drilled six production wells, four core holes and tested several water disposal options.
During 2007, we engaged an independent engineering firm, Netherland, Sewell & Associates to prepare reserve report for Peace River. The report indicated that there was an excess of one trillion cubic feet of gross gas in place under our acreage. Now that we have identified sufficient water disposal capacity, we plan to drill five additional production wells and construct and install production and gas treatment and sales facilities in 2008.
Consultations with the effective First Nations continue and we hope to commence gas sales from Peace River field in the fourth quarter. The Chattanooga Shale, our target in our Garden City prospect, located in North Central Alabama, represents a significant opportunity in close proximity to our existing operations, and a natural step up for exploration and development.
Based on our initial technically evaluation, this shale prospect shares many attributes of our coalbed methane projects. It is expected to be a large resource play, at shallow depths, with low finding and development costs, low operating costs, and long-life reserves.
Although gas production characteristics from shale formation generally differ from that of gas produced from coals, both types of plays lend themselves to low risk, multi-well, multi-year drilling programs where drilling and completion and infrastructure costs can be driven down overtime.
Our exploration department generated this play using surface geology analogs from old wells in this area, which allowed us to evaluate the Chattanooga Shale and acquire a significant land position at low entry costs. We have drilled five core holes and three production wells in the prospect area, and we plan to drill at least three additional production wells in 2008, at least one of which will be a horizontal well.
Initial production results are encouraging, but further drilling and production testing will be required before we can make a decision to develop this prospect. We have leased approximately 69,000 gross acres and continue to acquire leases in the prospect area.
Now I'd like to update you on the Virginia lawsuit, which centers around the validity of an easement granted to us by a land owner. CNX Gas Company's position is that its coalbed methane lease in this track, gives it the exclusive right to use the land and validate any right the land owner has to grant easements over the land. CNX has tired to shutdown our Pond Creek gathering line on this basis.
The Circuit Court held in CNX's favor last May. We bifurcated our appeal of the order, and have already had the portion granting injunctive relief to CNX overturned by the Virginia Supreme Court. At our last call in November, we had just learned that the Supreme Court agreed to hear our appeal of the remaining issue in the case.
The Virginia Supreme Court accepted all points that were raised by the GeoMet and the land owner, and denied all motions filed by CNX in the appeal. Supporting our position is an amicus brief filed by several interested parties in the area. The Supreme Court will hear oral arguments in their case in mid-April.
We have always been and continue to be open to a fair and reasonable settlement with CNX. However, discussions among the parties have not resulted in a settlement. During 2007, we have appeared before the Virginia Supreme Court three different times in connection with our CNX litigation. Each time the court held in our favor. We expect that they will do so again.
At this time, I will turn the call over to Bill to discuss our financial results.
Thank you, Darby, and good morning, everyone. GeoMet's financial position remains strong. Long-term debt at year end was $96 million, debt to total capitalization was 31% and bank debt constituted only $0.27 per Mcf of total proved reserve. At our request, the borrowing base under our credit facility was increased to $180 million during the fourth quarter and our banks have recently affirmed that amount based on our year-end reserve report.
Currently we have $96.5 million outstanding under our bank facility, leaving $83.5 million in unused capacity. Using the assumptions in our budget, we project bank debt at year end to be less than a $120 million; we therefore expect to retain significant liquidity throughout the year.
Net income for the fourth quarter totaled $1.6 million, as compared to $3.6 million in the prior year fourth quarter. Each of these quarterly periods was impacted by unrealized hedging gains or losses resulting from mark to market of our open natural gas hedge positions.
In the fourth quarter of this year, we recorded an unrealized pre-tax loss of $0.8 million versus an unrealized pre-tax gain in the amount of $2.3 million in the same period last year. Adjusted on an after-tax basis for these unrealized hedging gains and losses, net income would have been $1.6 million in the fourth quarter of 2007, as compared to $1.8 million in the prior year quarter.
For the year 2007, net income totaled $5.2 million versus net income of $17.3 million in 2006. Again, both these periods were impacted by unrealized natural gas hedging gains and losses. In 2007, we recorded an unrealized pre-tax loss of $3 million versus an unrealized pre-tax gain in 2006 of $16.9 million.
Adjusted on an after-tax basis for these unrealized hedging gains and losses, net income would have been $7.1 million in 2007 compared to net income $6.9 million in 2006. Average natural gas prices adjusted for realized hedging gains and losses were $7.80 per Mcf in the fourth quarter of 2007, as compared to $7.04 per Mcf in the prior year quarter, excluding the impact of hedges, the actual natural gas price realized with $7.07 per Mcf in the fourth quarter of 2007 versus $6.64 last year.
For the year, average natural gas prices adjusted for realized hedging gains and losses were $7.52 per Mcf in 2007, as compared to $7.37 per Mcf in 2006. Excluding the impact of hedges, the actual natural gas price realized was $6.97 per Mcf in 2007 versus $7.19 last year. The company generally realizes a positive differential as compared to NYMEX. The positive differential was approximately $0.10 per Mcf for the quarter and $0.09 per Mcf for the full year.
EBITDA for the fourth quarter was $6.7 million, however adjusted EBITDA, which excludes unrealized natural gas hedging gains and other non-cash charges were $7.6 million, 47% higher than the $5.1 million in the same period last year. For the year, EBITDA totaled $22.6 million, and adjusted EBITDA was $26.1 million, 15% higher than the $22.7 million an adjusted EBITDA for 2006.
Transportation costs were $0.27 per Mcf for the quarter, versus $0.44 Mcf last year, and $0.30 per Mcf in the prior quarter. Transportation cost in 2006 and the first quarter of 2007 reflect the $0.45 gathering fee we were previously paying to a third-party gather.
Once we began using our gathering line to transport our Pond Creek sales volume into East Tennessee's Jewell Ridge pipeline, this fee was eliminated although to a fairly small extent offset by higher operating cost and higher deprecation.
Compression costs were $0.36 per Mcf in the fourth quarter versus $0.32 per Mcf in 2006, and $0.35 per Mcf in the prior quarter. In general, the increase in the per unit compression cost was primarily due to excess compression capacity.
Lease operating expenses were $1.96 per Mcf for the fourth quarter, down from a $1.97 in the same quarter of 2006, and in the prior year quarter. G&A expenses were $2.3 million in the current quarter, as compared to $2.2 million in the prior year and $2.5 million in the proceeding quarter. The D&A rate for oil and gas properties was $1.26 per Mcf for the fourth quarter versus $1.20 per Mcf for the fourth quarter of 2006 and $1.30 for the preceding quarter.
In order to assure that we have adequate capital to carry out our business plans, we have a significant portion of our sales volume hedged, with recently added hedges approximately half of our estimated sales volumes are hedged through the summer of 2009. We've hedged approximately 20% of our sales in the winter of '09 and '10. These hedges have an effective floor price of $7.67 per Mcf for the summer periods, and $8.84 per Mcf for the winter periods.
Please refer to the hedged disclosure in our press release for more detail on our hedges. We've also added interest rate swaps to fixed-rate on a notional $25 million of our bank debt and actually as our priority we added another $10 million to that amount. So we have about $35 million of our debt hedged over periods ranging from two to three years, with an effective rate including our margin on our debt of less than 5%.
In January, we announced the capital budget for 2008 of approximately $49 million, at the same time we provided guidance that sales volumes would grow from 13% to 17% over 2007 levels. At this time we affirm the previous guidance.
With that, I will turn the call back over to the operator to arrange for any questions you may have.
(Operator Instructions). There are no questions at this time. Are there any closing comment?
Well, we just want to thank everybody for joining us today and this would conclude the conference call. Thank you.
This concludes today's GeoMet scheduled fourth quarter and fiscal 2007 earnings release conference call. You may now disconnect.