America's top independent gas reserve-holders have each arrived there by honing a strength in the U.S. marketplace, and they're sticking with it. Those that know how to produce U.S. tight gas are going after the resource in basins across the country. Those that understand offshore gas can be found all over the Gulf of Mexico, even pushing at the very limit of the eastern Gulf where the government has yet to allow access. Those that understand how to grow sensibly through acquisitions continue to acquire, changing the landscape of the industry with every dollar spent. The independents-EnCana Corp., Devon Energy Corp., Chesapeake Energy Corp., Anadarko Petroleum Corp. and XTO Energy Inc.-have catapulted themselves to ranking with super-majors BP Plc, ExxonMobil Corp., ConocoPhillips, Chevron Corp. and Royal Dutch Shell in their U.S. gas-holdings. Some have even advanced ahead of Chevron and Royal Dutch Shell. While year-end 2005 figures for each holder of U.S. gas reserves weren't in yet at press time, year-end 2004 figures plus leading reserve-holders' announcements of acquisitions, divestments and additions during 2005 indicate the Top 10 will change significantly when the final numbers arrive later this year. Less than a decade ago, which companies held the most U.S. gas-production potential was not considered as important as a ranking of holders of North American oil-production potential. Natural gas prices have historically been soft, compared with the volatility of oil. Today, eyes are turning to those who hold the domestic gas reserves, due to the growing importance of natural gas to the U.S. economy, national security and environmental concerns, the fact that there is limited U.S. natural gas import capacity other than from Canada, and the firming of natural gas prices. Increasingly, the gas reserve-holders are U.S.-based independents, many of whom have grown their positions in part as beneficiaries of gas-asset divestments by the super-majors, which sought bigger, predominantly oil, potential overseas. Where will these independents add U.S. gas reserves next? "We'll tell you that after we've finished buying everything," they say. Here, executives with each company discuss their U.S. gas strategy. Anadarko Petroleum Corp. The Houston-based independent ended 2005 with total global proved reserves of 2.45 billion barrels of oil equivalent (BOE) (54% gas) and average fourth-quarter gas output was 1.38 billion cubic feet per day. At year-end 2004, its U.S. reserves totaled 1.65 billion BOE (62% gas), according to a review by John S. Herold Inc. and Harrison Lovegrove & Co. The company's U.S. assets are primarily in Texas, Louisiana, Alaska and the deepwater Gulf of Mexico. While it is a leading U.S. gas reserve-holder, Anadarko doesn't target gas exclusively, says Mark Pease, senior vice president, exploration and production. "We look at the plays that fit our core skill sets, regardless of if they're oil or gas. "In North America, we see a lot of potential for gas, but our goals going forward are not to concentrate on gas necessarily. We don't have a target to get to a certain number in gas reserves by any certain time." When Anadarko chief executive Jim Hackett joined the company in 2003, he set out to refine the company's business model and strategy to focus on its strengths. "Our strengths came down to grassroots exploration and the delineation and development of unconventional resources, including tight gas, coalbed-methane, enhanced oil recovery and fractured reservoirs," Pease says. We like to focus particularly on unconentional resources because the target is large and people know they're there. For example, with tight gas, people have known for years it is there. We just had to figure out a way to make that gas economic through geoscience and engineering." Anadarko has been pursuing tight gas for more than two decades, starting in the Golden Trend of southern Oklahoma and extending to the Bossier play of East Texas. "Public data on remaining undiscovered reserves in North America estimates about 1,000 trillion cubic feet," Pease says. "Of that, 70% is unconventional. We're taking a skill set we've developed over the last 20 years, through working with tight gas and unconventional reservoirs, and we're leveraging what we've learned to look for new areas to apply that skill set." Anadarko has also been a successful gas finder in the deepwater Gulf, where it announced more discoveries in 2005 than any other company. "The Gulf is more conventional, grassroots exploration. We see a lot of potential there. There are favorable economics, the technology has advanced, and we've had good success there." Its offshore program in the Eastern Gulf of Mexico Lease Area 181 has led it to the very borders of leases open for exploration. The company recently made several discoveries on the edge of the easternmost lease area, leading it to believe that more success will follow if more acreage is opened to exploration. "The biggest challenge for us is access, both onshore and offshore," he says. "Offshore, a lot is still off limits, and onshore, a lot is federal land, so what is open involves a lengthy regulatory process. The government is really trying to satisfy a lot of stakeholders, and we believe a better balance can be found." Other challenges include rising costs and staffing up. "The manpower to drive activity has not ramped up as quickly as activity." And, what manpower the industry has directed at growing U.S. gas production has yet to result in a significant increase in supply, he adds. Because of this, increased liquefied natural gas (LNG) imports will be important to U.S. gas supply, he says. Rather than being strictly a competitor with imported gas supply, Anadarko is working to get into the LNG import business via its Bear Head LNG import terminal project on the Nova Scotian coast. Construction should begin this spring, and first LNG may be received in 2008. As for the next big U.S. gas play, Pease is confident Anadarko will be open to being a part of it and that it will be unconventional. "Anadarko is always looking for new plays," he says. "We have an exploration mindset and that helps us look in new areas. They don't have to be proven for us to try them. In 2005, we gained access to some 1.9 million new acres in a number of different plays. If we can get the eastern U.S. Gulf opened, and I'm hearing a little more will open, that could be a very good area for us." Chesapeake Energy Corp. The Oklahoma City-based company is the second-largest U.S. independent gas producer and the most active U.S. driller with 75 rigs at work. It owns interests in approximately 29,800 producing wells and has estimated proved reserves of 7.3 trillion cubic feet of gas equivalent (92% gas, all onshore the U.S.). Its primary operating area is the Midcontinent, and it also holds significant land positions in the Appalachian Basin, Permian Basin, South Texas, Barnett Shale and ArkLaTex region and on the Texas Gulf Coast. Its gas strategy is to extend plays horizontally and vertically, says Jeffrey Mobley, vice president, investor relations and research. "We do explore and we also try to increase the size of our positions through incremental, bolt-on acquisitions and leasing," he says. The company was primarily an Oklahoma and Texas player until its acquisition last year of Columbia Natural Resources, extending its focus to include the Appalachian Basin. The company has no plans to expand offshore or abroad, Mobley says. "We think the market underestimates the risk of being in international operations as well as being offshore." Risks offshore include hurricanes, technological failures, timing to get projects online and a lack of exploration diversity. "You can spend several hundred million dollars on any one well and it may or may not be successful. If it is, it might be years before the production comes online." Chesapeake's focus on gas was the result of a redefinition of the company's strategy in 1998. Gas was trading at a significant discount to oil at the time, the company believed gas demand would grow, and it believed it could make a niche in the gas arena. "If we were to try to find a big quantity of oil, we just don't think it can be done." For now, Chesapeake isn't interested in taking its gas focus into the Rockies. "We generally prefer to be in areas where we're wanted," he says. Obstacles in the Rockies include permitting delays and environmental opposition. "Also, we think the region is prone to occasional basis blow-outs due to takeaway capacity, and it's not an area in which we've chosen to build an exploration expertise either, so it's not likely that we would choose to be a player in the Rockies. "It's also a very competitive region, which is another reason we would choose to focus elsewhere." While its acquisitions make the most headlines, the company is an active driller. It now owns 30 rigs and expects to own 60 rigs by year-end. "Owning rigs is a little bit of a financial hedge in terms of exposure to rising drilling costs. More importantly for us is having the access to rigs to accelerate drilling on our properties," Mobley says. Having leases and rigs doesn't make the gas business easy, though. "Gas is getting hard to find. We were able to invest earlier than most to build a large inventory. Our reserve-life has been extended to about 14 years, so our depletion rate, while always a challenge, is below the industry average, and that makes it easier for us to grow." Chesapeake is less concerned today about the impact of increased LNG imports than it was in the past. "The U.S. will have to compete for LNG cargoes with other markets worldwide. The idea that LNG will come in and slump the U.S. market, and that the U.S. is the only market that will demand LNG cargoes, is probably not right." Devon Energy Corp. In the U.S., the Oklahoma City-based independent produces gas from most of the country's major basins, including regions like the Barnett Shale, East Texas, West Texas, New Mexico, the Rockies, the Powder River Basin and the Gulf of Mexico. It ended 2005 with total global proved reserves of 2.1 billion BOE and average production of 619,000 BOE per day. At year-end 2004, its U.S. reserves totaled 1.2 billion barrels of oil equivalent (68% gas), according to Herold and Harrison Lovegrove. Currently, gas is 62% of its company-wide production and essentially all of it comes from North America, says John Richels, president. The company's gas strategy is to focus on areas where it can achieve critical mass-large acreage positions and high working interests. The company also tries to ensure it has significant ownership in or access to takeaway capacity to get its product to the market. "Traditionally we have focused on unconventional gas, including the black shale in the Barnett, which is unconventional because of the tightness of the rock," Richels says. "Until five or six years ago, the industry hadn't fully developed how to get gas out of those formations." Mitchell Energy & Development had the key and Devon bought the company in 2002. A core area for Devon, the company holds some 550,000 acres in the play and is responsible for some 50% of Barnett gas production, making it the largest operator in the play. While Devon pursues both conventional and unconventional plays, its core competency is in the unconventional, Richels says, particularly coalbed-methane and shale. It aims to become more of a player in the latter. The company's gas potential is extending to Canada's Beaufort Sea, where a well was recently spudded, Richels says. Devon doesn't focus solely on gas. "We have always thought a reasonably balanced portfolio is appropriate," Richels says. But he expects the supply and demand balance to remain tight through the coming years. "It's not readily evident where the new, large gas supplies are going to come from in the next few years. Our strategy will be to continue to develop the large opportunities we have and to expand our gas production." Unconventional resources are where Devon is placing its bet. "There are still some very prospective areas in the U.S." EnCana Corp. The Calgary-based independent's U.S. subsidiary, EnCana Oil & Gas (USA) Inc., is completely gas-focused. As of year-end 2004, it had U.S. proved reserves of 5.2 trillion cubic feet of gas equivalent (Tcfe), some 89% of it natural gas, while 2005 production was projected to be 1.1 billion equivalent per day from a total net land position of 4.7 million acres. The company has acreage and production in the Wind River, Green River, Jonah, D-J, Piceance, Paradox, Fort Worth, East Texas and Permian basins. Its focus on tight gas dates back 30 years, according to Alan Boras, manager, media relations. "The company has had a long history over three or four decades of development of multi-layer tight-gas sands in southern Alberta," Boras says. EnCana took that experience into the U.S. Rockies into Jonah Field and the Piceance Basin. In 2004, it firmed its position in the area by purchasing Denver-based Tom Brown Inc, gaining 1.2 Tcfe of proved reserves, mostly in the Rockies. Rock formations there mimic those EnCana was already familiar with in Alberta. "The technologies and methodologies we were already using in Alberta were similar," Boras says. "It was about 10 times as deep in the U.S. Rockies and it produced about 10 times as high a volume of gas, because there's about 3,000 feet of reservoir in the Jonah that you can fracture and produce gas from." Since 2004, the company has moved into the Fort Worth Basin as well as East Texas and the Permian. "We chose where we wanted to go in the U.S. where the rock was such that it is in our core competency of tight-gas development and our resource-play, unconventional-development strategy." The company continues to look at other opportunities and recently made some acquisitions in the Maverick Basin in South Texas. "That's an area we will look to potentially develop." The company sold its Gulf of Mexico position in 2005 and has no plans to return. "We're done with that," Boras says. "The company decided it wanted to focus on onshore North American unconventional resources, and developing offshore fields is not among our core competencies." For a U.S. gas-focused producer, what impact could increased LNG imports have? "We don't anticipate that it will come in and make a dramatic difference in the overall market. It will be an incremental supply that will generally be quite welcome because of the rising demand and the continued preference for gas." XTO Energy Inc. The Fort Worth, Texas-based independent has a production mix of 80% gas, 85% of which is unconventional, and all of which is located onshore the Lower 48. At year-end 2005, its preliminary proved reserve estimate was about 7.5 Tcfe with production of 1.3 billion cubic feet equivalent per day. XTO has gas operations in East Texas, the Fayetteville and Barnett shales, and the Piceance, Arkoma, San Juan and Permian basins. The only major gas-producing area in the U.S. in which XTO is not involved is offshore, and the company has no plans to move there, says Keith Hutton, president. "In the Lower 48 onshore, there exists the opportunity to acquire daily production of about 10 billion cubic feet," he says. "Currently we produce only 1.1 billion per day. We have plenty of room to grow in the U.S. We see no reason to change our strategy." That strategy has been the same since the company was founded 20 years ago, and it continues to work. Its record of growth is 50% through the drillbit and 50% through acquisitions. On average each year, XTO has replaced 400% of its reserves. The primarily acquire-and-exploit company devotes some 5% of its annual development budget to exploration, which is usually only spent on expanding its big unconventional plays, Hutton says. "The fact that we focus on unconventional is an artifact of our acquire-and-exploit strategy," he says. "I like to say we were a resource player before resource players were cool. Our goal is to acquire properties with a shallow decline rate of 7% to 10%. We're usually in geologically complex, multi-pay areas that have been overlooked and underexploited. This strategy has naturally put us into unconventional areas." As an acquire-and-exploit company, the biggest challenge XTO faces is when buying properties becomes too expensive, Hutton says. "In 2005 we spent $1.7 billion on acquisitions, mostly in the beginning of the year before prices went up," he says. "Hurricanes Katrina and Rita made acquisitions almost impossible, but now prices are back down and it is a better time to reenter the market. "That always happens, though. You'll have stall periods, but someone's always trying to sell something." Meanwhile, XTO's drilling inventory can grow base production at 10% for three years without additional acquisitions. Competition from LNG could affect XTO because the majority of the proposed terminals are planned for the Gulf Coast-near much of XTO's production. "In East Texas, we currently produce 700 million cubic feet per day, so we've signed up for a new pipeline that will give us enough takeaway capacity to double that rate," he says. "The pipeline will go from the Barnett to Louisiana and we'll use it to get our Barnett gas away from the Gulf Coast LNG terminals." Shales are the next great gas play, and the Barnett may prove to be the largest, he adds. "In the Rockies, the San Juan Basin was the first and best coalbed-methane play," he says. "We think the Barnett will be the shale version of the San Juan Basin. There will be a lot of people out there trying to develop shale elsewhere, but the Barnett will be the biggest."

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