Across North America, producers are spending millions of dollars more each year on developing coalbed-methane (CBM) resources. While these wells are not known for prolificacy, the unconventional gas is reliable, dependably surfacing at small but steady amounts, and for years. It is also somewhat easy to amass amounts of CBM reserves and production that are material to the bottom line, relatively speaking. For example, a CBM well, notoriously shallow, may cost $50,000 to drill; a shallow Gulf of Mexico well may run $20 million. Here's a review of some North American CBM-developers' recent activities and plans. Admiral Bay Resources Inc. Denver-based Admiral Bay Resources Inc. (Toronto Venture: ADB) is grabbing investor attention with its CBM projects in the Cherokee Basin in Kansas and in the Appalachian Basin in Pennsylvania. Its board members include Logan Magruder, formerly of Berry Petroleum and now at start-up Quantum Resources with ex-Westport Resources chief Don Wolf; and Greg McMichael, formerly an analyst with A.G. Edwards & Sons and presently a director on the Denbury Resources and Matador Resources boards. The company, which was originally based in Canada, also recently closed its Toronto office. Some 40% of its investors are European. "It's a long story how they got there," says Steven Tedesco, Admiral Bay president and chief executive officer. The micro-cap company plans some 200 wells through July 2007 on its Kansas and Pennsylvania CBM acreage. Initial production per day per well is expected to average some 30,000 cubic feet. Total-company 12-month production through this July may be some 350 million cubic feet, net. Capex is $26 million, to be funded largely from a new $40-million debt facility from Macquarie Bank that is to become available this month with an initial $15 million available. The company has no debt currently. Its capex budget for 2006-07 includes $21 million for development of Kansas acreage, and $1.9 million for its Revloc project in Pennsylvania. The company is presently fully funded. Most wells pay out in less than two years and "we don't have to worry about dry holes," Tedesco says. Total production from the Shiloh project in Kansas, where Admiral Bay is drilling 3.5 new wells a week, has increased to between 1.1- and 1.25 million cubic feet per day. In 2006-07, the company will drill 110 wells there. In the Appalachian Basin, a seven-well Revloc test pilot is to start this summer. The company plans to drill more than 200 wells this year and an additional 200 wells in 2007. The company has 23 billion cubic feet (Bcf) of proved reserves from its Shiloh and Devon projects in Kansas, and an additional 290 Bcf of probable and possible reserves from those and three others: Mound Valley, Swordfish and Santa Rita in Kansas, and Revloc. Potential drilling locations number 1,880 on the 151,000 acres. Costs are such that the company can make a profit at $2 gas prices, Tedesco says. The Shiloh project is the company's main focus right now, he adds. Revloc is the wildcard: the coals there could have two to three times higher gas content than that of the Kansas coals, so Admiral Bay may switch its focus to that acreage, depending on how the pilot works out. The Pennsylvania potential carries another bonus: Admiral Bay's Kansas gas receives a roughly $1 discount to the Nymex price, but Pennsylvania gas is expected to receive a $1.50 premium, he adds. The Revloc project consists of 17,800 gross acres in Cambria County, Pennsylvania, on a coalbed the county closed to mining some 25 years ago because the coals were too gassy for safe mining. Possible reserves are 9.88 Bcf from 220 potential drilling locations per 80-acre spacing, Tedesco says. Seven vertical test wells are expected this summer. Targeted peak gas production is 50,000 to 500,000 cubic feet per day. In Kansas, Admiral Bay gets a drilling permit in five days, Tedesco adds. "It's really a nice place to work." Drilling and completion costs $85,000 to $200,000 per well to 450 to 2,200 feet, or $8 a foot. The same well in Utah would cost $30 a foot, he says. Admiral Bay's operating costs per well are $400 to $800 a month, and production averages 50,000 to 120,000 cubic feet per day. Reserves average 200 million cubic feet per 80 acres. Shale formations in each well have been found to contribute gas, so Admiral Bay is completing in those now too. Storm Cat Energy Corp. Calgary- and Denver-based Storm Cat Energy Corp. (Amex: SCU; Toronto Venture: SME) has CBM interests in five operating areas in the U.S. and Canada and, altogether, is operator of some 381,000 gross (159,000 net) acres in North America. Its 2006 capex budget is $32 million; it spent $25 million in 2005. In Elk Valley, British Columbia, where it is working on a farm-in with a major producer on 78,000 acres, two new wells that were drilled in December were recently completed. Production from the first ranged from 124,000 to 204,000 cubic feet per day; the other well produced for five days at 75,000 cubic feet daily until a downhole pump failure. The results were better than expected and the company plans six more wells starting in June and six more locations are being considered for this fall, says Scott Zimmerman, president and chief executive. Zimmerman is formerly of Evergreen Resources Inc., which turned CBM potential in the Raton Basin into a $2.1-billion company that was sold in 2004 to Pioneer Natural Resources Co. In Alberta, small-cap Storm Cat has some 11,668 gross acres prospective for Mannville coal development. And, in Alaska, a recent well onshore Cook Inlet Basin encountered a significant amount of coal as well as conventional sandstones. The company also has producing properties in Wyoming's Powder River Basin (142 wells making a total of 4 million cubic feet per day.) Of its Powder River Basin assets, some 7,800 gross acres are prospective for CBM in the Jamison/North Twenty Mile and Northeast Spotted Horse areas, in Campbell County, Wyoming. A total of six coal seams exist in the Jamison/North Twenty Mile area, including the Anderson and Canyon. The properties are producing some 750,000 cubic feet per day from 28 wells (26 operated by Storm Cat) from the Anderson and Canyon coal seams. The company believes two of the lower seams, Cook and Wall, are thick enough to merit testing and development. The Northeast Spotted Horse project, acquired in 2005, is northwest of Gillette, Wyoming, and consists of 6,320 gross contiguous acres. Producing since 2001, the project consists of 116 wells, of which Storm Cat operates 114, and production is more than 3.25 million cubic feet per day from various Fort Union seams. Penn Virginia Corp. Radnor, Pennsylvania-based midcap Penn Virginia Corp. (NYSE: PVA) has CBM assets in Appalachia where its production was 38 million cubic feet per day in 2005, including conventional gas. Proved CBM reserves total some 36 Bcf; probable and possible total 72 Bcf. Gross reserves per CBM well are 865 million cubic feet. The composite after-tax rate of return is approx 90% on the 51 wells drilled to date, using actual prices through mid-April and a $6 gas price held flat for the future. The rate of return is more than 250% at $8 gas for new wells. At that rate, CBM is the company's highest after-tax rate-of-return play, compared with its Selma Chalk (Mississippi) and Cotton Valley (East Texas/North Louisiana) returns, according to James Dearlove, president and chief executive. The company has owned Appalachian coal for more than a century, leasing it to others to mine. The years of knowledge play into the company's success in CBM in the area, Dearlove says. "We know those coals. We've owned and managed coal reserves for more than 100 years." This part of Penn Virginia's business is part of a master limited partnership, of which it owns some 40%. Development of its CBM play employs horizontal wells in a joint venture with privately held, Dallas-based CDX Gas LLC, which has a patented Z-Pinnate drilling technique for tapping more gas resources from a single well site. The venture with CDX, which was recently purchased by Los Angeles-based Trust Company of the West, involves 160 drilling locations and another 200,000 acres are being evaluated. The balance of Penn Virginia's CBM program has 70 drilling locations and another 40,000 acres are being evaluated. With the horizontal-drilling technology, Penn Virginia expects to drain an average of 400 acres per well, tapping an estimated 880 million cubic feet per well of ultimately recoverable gross reserves at finding and development costs of $1.40 to $1.75 per thousand cubic feet (Mcf). The horizontal technique results in pay-out in approximately one year and recovers 85% to 90% of the gas in fewer than 10 years, Dearlove says. Some 50 wells have been drilled, representing more than 200 miles of horizontal laterals ranging from 15,000 to 86,000 feet per series. Gas potential isn't a question. "The only limitation we have is take-away capacity," Dearlove says. CNX Gas Corp. Newly public Pittsburgh-based CNX Gas Corp. (NYSE: CXG) is one of the largest Appalachian gas producers-some 13.6 Bcf or 152 million cubic feet per day in the first quarter during which the company brought an additional 70 CBM wells online. Year-end 2005 proved reserves totaled 1.13 trillion cubic feet (Tcf) of which 552 Bcf are proved developed and 578 Bcf are proved undeveloped. By spending $650 million during the next three years, CNX expects to increase annual production to 76 Bcf by 2008, which would be a more than 50% increase from the 48.4 Bcf produced in 2005, says Nick DeIuliis, chief executive and president. CNX is a spin-out of coal company Consol Energy Inc., and has rights to CBM from 4.5 billion tons of coal reserves and other resources controlled by Consol. CNX had no debt as of April, and $200 million of credit capacity. DeIuliis estimates the company's proved undeveloped reserves can be brought online at a constant cost of $0.65 per Mcf, based on a third-party assessment. "We'd like to dispel the myth that unconventional gas is high-cost gas," he says. In the first quarter of 2006, CNX reported cash costs of $2.07 per Mcf and total unit costs of $2.73 per Mcf. In 2005, CNX's net cost per Mcf of gas produced was $2.72; cash costs per net Mcf were $2.16 in fourth-quarter 2005. Total costs per Mcf in the fourth quarter were $2.90. The company's 2006 capex budget is $190 million for 215 new wells at $400,000 each. Each is expected to produce 96,000 cubic feet per day initially. Some 23 additional new, vertical-to-horizontal wells are planned for 2006 at $1 million each and 460,000 cubic feet per day of initial production is expected from each of these. CNX's drilling is predominantly in central Appalachia but growing in northern Appalachia and eastern Tennessee. In the first quarter, of the 70 wells the company brought online, 68 are in central Appalachia; one, northern Appalachia; and one, Tennessee. "If you are bullish on the E&P sector or gas prices, CNX Gas offers the highest return metrics within the sector...," DeIuliis says. "If you are bearish..., CNX Gas is the last stock you want to sell within the sector." St. Mary Land & Exploration. Denver-based St. Mary Land & Exploration Co. (NYSE: SM) has put together some 159,000 net acres (53% federal, 37% fee and 10% state) that are prospective for CBM in the Hanging Woman Basin, which straddles the Wyoming-Montana border. The basin is a sub-basin of the Powder River Basin. Development began in 2003 and 126 wells were producing at year-end 2005. While dewatering, production at year-end was 3.7 million cubic feet per day. Total reserves are estimated at 833 Bcf net (25 Bcf proved, 100 Bcf probable and 708 possible). The company has 3,000 potential drilling locations, with 140 to be drilled in 2006. Capex for 2006 for the CBM play is $27 million. "We think this will provide a real legacy asset for the company and potentially double the reserve base," says Mark Hellerstein, St. Mary chairman, president, and chief executive. The acreage is fairly contiguous, which is helping with development of the gas potential, according to Hellerstein. "We don't have to compete with the neighbors in terms of the drainage pattern, so we can develop the resources in a more orderly fashion." The Hanging Woman Basin coalbed has three benches of coal, each with three coal seams (for a total of nine seams) throughout most of its acreage. Traditional CBM development in the Powder River Basin has used 80-acre spacing; however, due to its contiguous acreage position, St. Mary is able to drill on 160-acre spacing. Moreover, St. Mary is using a multi-seam completion technique, employing a downhole tool developed by one of the company's engineers. The result is that St. Mary is able to drill fewer wells per section, which significantly improves the economics when compared with a more traditional program. "That's been one of the real positive surprises we've seen," Hellerstein says. "Originally, our economics didn't contemplate this multi-seam completion technique. In addition to the improved economics, we have less impact on the surface, which is more environmentally friendly." Current development has focused on the shallow coal packages, but the company has begun drilling wells for the intermediate coals, and will begin additional testing of the deeper coals this year, with two to four horizontal tests planned. Pioneer Natural Resources Co. Irving, Texas-based large-cap Pioneer Natural Resources Co. (NYSE: PXD) acquired a huge CBM position in the Raton Basin of southeast Colorado and northeast New Mexico from Evergreen Resources in 2004 and has expanded that position to include projects with sizeable potential in northern Colorado and Utah. The company also has a CBM position in the Horseshoe Canyon coal, Alberta. Its year-end 2005 reserves in the Raton Basin totaled 246 million barrels of oil equivalent (BOE); in Canadian CBM, 24 million. The company estimates another 130 million BOE of resource potential from these assets. In the Raton Basin, Pioneer owns a portion of the drilling equipment being used, acquired with the Evergreen assets. "We are saving $25- to $30 million a year by owning our own equipment," says Scott Sheffield, chairman and chief executive. The company owns 310,000 gross acres and drilled 289 wells in the Raton in 2005. Some 1,650 drilling locations remain, and 330 new wells are expected this year. The internal rate of return is approximately 35% at $6.50 gas, according to Sheffield. This year, Pioneer is focusing on more efficiently recovering the CBM, such as by boosting compression, he adds. Elsewhere in the U.S., Pioneer has three emerging CBM plays-Castlegate, Lay Creek and Columbine Springs-under way totaling 228,000 gross acres in Utah and Colorado. "These are three very important areas. We'll make a decision on all three plays probably by year-end." All 27 wells drilled to date are producing gas. Pioneer is assessing the time it takes for the wells to dewater. Another 35 wells are awaiting completion or pipeline connection. Another 50 wells are to be drilled this year. Pioneer estimates the gross resource potential of the acreage is 2- to 5 Tcf. Pioneer is operator and holds 50% of the Lay Creek pilot CBM project, involving 118,000 acres now and expanding to some 200,000. Work so far involves refracing and reworking wells that were part of a prior operator's pilots. In Alberta, Pioneer has 70,000 gross acres in the Horseshoe Canyon CBM project with some 500 drilling locations. More than 150 wells were drilled in the second half of 2005 and 60 were producing a total of 5 million cubic feet per day at year-end. Plans are for another 200 wells this year and hooking up roughly 300 into sales by year end. Pioneer estimates its rate of return on these wells is 70% at $6.50 gas, and its net resource potential is roughly 200 Bcf, which could grow to more than 250 Bcf with down-spacing, Sheffield says. At the company's Mannville project in Alberta, it has 75,000 gross acres and plans eight horizontal wells to test three pilots this year. The net resource potential is 250 Bcf. "Canada will be one of our fastest-growing areas going forward," Sheffield says. XTO Energy Inc. CBM figures prominently in large-cap Fort Worth-based gas producer XTO Energy Inc.'s (NYSE: XTO) gas story, representing 12% of company-wide production of 1.46 Bcf equivalent per day. The figure is particularly significant in terms of overall U.S. gas production-XTO Energy is one of the top U.S. gas producers, and a great deal of the output comes from CBM wells. Louis Baldwin, executive vice president and chief financial officer, names CBM among the onshore U.S.-focused company's "big four" resources; the other three are tight gas, shale gas and tight oil potential. The company's CBM assets are in the Rockies in the Powder River, Uinta, San Juan and Raton basins. CBM production is 160 million cubic feet per day, and is expected to grow to more than 250 million. The company believes Rockies coals have higher gas content and better well deliverability. Its current drilling inventory on its CBM acreage is 700 and 900 wells, possibly holding 650 Bcf of net potential reserves. In the San Juan region, the company's CBM focus is on the Fruitland, Raton, Vermejo and Ferron coals, producing 160 million cubic feet per day. It has more than 100 drilling locations in the San Juan Basin (where it drilled 140 wells in 2005), 200 to 300 in the Raton, and 150 to 200 in the Uinta. Its development costs for its CBM wells are 40 to 65 cents per Mcf.