Long before it achieved statehood in 1890, Wyoming-derived from the Delaware Indian word meaning "land of vast plains"-was recognized for its oil springs by prospectors and pioneers alike. As they made their long trek along the Oregon and Overland trails during the 1830s, many of them scraped up the surface oil and mixed it with flour to make axle grease. Some 50 years later, in 1883, amid rolling valleys, buttes, mesas and the sharply sculpted features of the Rockies, the region's first oil well was drilled. Today, however, Wyoming's real hydrocarbon treasure-particularly in the Green River Basin in southwestern Wyoming-is natural gas. Lots of it. "The Rocky Mountains are the Persian Gulf of natural gas," says Peter A. Dea, president and chief executive officer of Denver-based Western Gas Resources. That's largely because some 85% of the region's remaining gas resource has yet to be discovered and developed versus 50% in the more historic producing regions of the U.S. It's also largely because, during the past decade, there have been more multi-hundred-billion-cubic-feet (Bcf) and multi-trillion-cubic-feet (Tcf) gas discoveries made in the Rockies than anywhere else in the onshore U.S., he says. According to various estimates, at least 300 trillion cubic feet equivalent (Tcfe) of gas has yet to be recovered in the Rockies, and Dea says probably one-third is in the Greater Green River Basin. He notes that in 2001, the Rockies as a whole accounted for 78% of total annual U.S. gas reserve additions, with the Greater Green River Basin a significant part of that contribution. "Today, the Green River Basin comprises 40% of Rockies gas production." The 19,000-square-mile Greater Green Basin is comprised of four sub-basins and five long structural arches or anticlines. The sub-basins, from east to west, are the Red Desert, Washakie, Sand Wash and Hoback; the structural arches, from west to east, are the Moxa Arch, Pinedale Anticline, Rock Springs Uplift, Wamsutter Arch and Cherokee Arch. Within these sub-basins and arches are mainly Cretaceous-age pay zones, including-from top to bottom-the Lance, Mesaverde, Almond, Lewis, Frontier, Muddy and Dakota formations. "While these are generally 6,000- to 14,000-foot-deep, low-permeability, tight-gas reservoirs, they are prolific in size and number and contain long-lived gas reserves," explains Dea. Larry Busnardo, E&P analyst for Petrie Parkman & Co. in Denver, sees renewed emphasis by independents on the Greater Green River Basin, with the May 1 expansion of the Kern River Pipeline-which added 900 million cubic feet of gas-takeaway capacity from the Rockies. "Operators are ramping up their capital budgets and contracting more rigs, so you're definitely going to see more exploration and development activity in the region," he says. "Not only is there now more gas-takeaway capacity to the west via the Kern River Pipeline, but also producers are eyeing the planned Cheyenne Plains Pipeline-due onstream in 2005-which will add further Rockies gas-takeaway capacity going east." The analyst notes that with Kern River coming online, the basis differential between Rockies and Henry Hub gas prices-as high as $2.50 to $2.75 per million Btu (MMBtu) last fall-has narrowed to around $1. Combined with the recent improvement in gas prices nationwide, this means independents in the Rockies are now getting closer to $5 for their gas versus $1.50 to $2 last year. Says Busnardo, "This pricing environment, coupled with the huge undeveloped potential of the Greater Green River, gives producers like Tom Brown, Forest Oil, Westport Resources, Western Gas Resources and Ultra Petroleum plenty of running room, in terms of expanding their existing exploration and development programs there." Indeed, these operators are now in a position to move quickly to tap the region's huge tight-gas inventory. But they're not alone. New basin faces EnCana Oil & Gas (USA) Inc., the Denver-based arm of Calgary's EnCana Corp., entered the U.S. Rockies three years ago with the $600-million acquisition of Wyoming's McMurray Oil Co. Today, it holds 2 million net acres throughout the Rockies, including 600,000 net acres in the Greater Green River Basin. There, it has interests in 1,000 wells, 500 of which it operates-400 of those in the Jonah Field. Its net daily production in the entire basin: 400 million cubic feet, 95% of that from operated wells. "While we're involved in every sub-basin in the Green River, most of our operations-involving the drilling of some 100 wells annually-are focused on the Jonah Field in the Hoback Basin, about 90 miles north of Rock Springs," says Roger Biemans, president. "To date, the industry has produced 1 Tcf of gas from Jonah; its ultimate reserve potential, however, is estimated to be at least 3 Tcf." In the Jonah Field, the operator has been targeting the prolific Upper Cretaceous Lance formation, at depths ranging from 8,000 to 13,000 feet. While its average drilling and completion costs per well have been running $1.5 million, the company-whose capex budget in the basin this year will again be $150 million-is paying a lot of attention to pruning unit costs. "Dollars spent per thousand cubic feet (Mcf) is the key consideration," says Biemans. "In this equation, we devote a lot time to figuring out how to reduce the numerator (dollars) and increase the denominator (Mcf). Since we started operations in Jonah, we've been able to increase our reserves and initial productivity per well by about one-third while keeping costs flat." He points out that in 2000, reserves per well in Jonah amounted to 4.5 Bcf; today, reserves per well average 6 Bcf. While the EnCana arm benefits from economies of scale and the use of drillbits that make hole much faster than before, its completion technology is having the greatest impact on well economics. "In our hydraulic fracture stimulations, we're using better, cleaner fluids to carry the pumped sand into reservoirs," he says. "This greatly affects the rates at which wells flow back from stimulated reservoirs. Today, with new fluid technology, we're able to get gas out of intervals that we previously couldn't." As the result of all these steps, the producer's drilling and completion costs are 25% less than they were three years ago, Biemans stresses. "That's important, because where the rocks are tighter and the formation pressures are a little lower, you need to have a better cost structure to make a resource into a reserve." Although 75% of the operator's current Rockies production comes out of the Greater Green River, it has aggressive development plans elsewhere in the Rockies, particularly in Colorado's Piceance Basin, where this year it will drill some 300 wells. "During the ensuing five to 10 years, the Piceance will also have multi-Tcf reserves discovered and developed." Three years ago, another oil-patch giant, Anadarko Petroleum Corp., decided it, too, was going to put more E&P focus on the Rockies. And it did-in a big way. Through its $4.3-billion merger with Union Pacific Resources, the company picked up 7.9 million net acres of the federal land grant made to the Union Pacific Railroad in the 1860s. Today, some 1.6 million net acres of the Houston independent's total 8.3-million-acre position in the Rockies is centered in the Greater Green River Basin. That doesn't sound like much of a slice of its acreage pie until one considers that the basin accounts for about half of Anadarko's 300 million barrels of oil equivalent (BOE) of reserves in the Rockies, and 40,000 equivalent barrels of daily production from around 2,650 wells. "There's tremendous resource potential in the Greater Green River; some estimates suggest it holds undiscovered reserve potential of 85 Tcf of gas and about 3 billion barrels of oil," says Mark L. Pease, Anadarko vice president, U.S. onshore and offshore exploitation, development and production operations. "Given the basin's many productive formations, it's a very prolific hydrocarbon region versus other areas of the U.S. That's one of the core reasons we did the merger with UPR." Operating mainly in the central to eastern part of the Greater Green River, the company has a large position in the Wamsutter Arch, as well as the Brady and Table Rock fields-all tight-sands gas plays. It also has early-stage coalbed-methane gas projects under way in the Copper Ridge and Atlantic Rim fields. Meanwhile, it's redrilling the Monell Field, preparing that for an enhanced oil recovery program. For the most part, Anadarko's gas production is out of the Lewis, Almond, Weber, Madison and Nugget formations; the Brady Field produces out of the Frontier and Dakota. "Last year, we operated about one-third of the 120 wells we drilled in the Green River; this year, we'll operate 75% of our planned 190 wells for the basin," says Pease. "With this increased activity, we should see our production in the region rise about 15%." For the Rockies overall, the company's 2003 capex budget will jump to $240 million from $100 million last year. Taking a proactive stance amid Rockies gas prices and basis differentials much better than a year ago (see accompanying chart), Anadarko has already signed up for 100 million cubic feet per day of firm gas-takeaway capacity on the planned Cheyenne Plains Pipeline, which will carry 550 million cubic feet per day eastward from the Rockies. Besides kick-starting coalbed methane and enhanced oil recovery projects in the basin, the company has also taken over operatorship of the Table Rock gas-processing plant. "This should allow us to quadruple daily production there from 15 million cubic feet to about 60 million." In addition, Anadarko, which last year drilled around 1,000 wells companywide, is leveraging that experience to reduce drilling and completion costs in the Greater Green River. "The use of polycrystalline diamond cutter (PDC) bits in Texas has allowed us to substantially reduce drilling time there; so we've taken that technology to the Rockies and are realizing 20% lower drilling costs," says Pease. "Also, because our activity level is increasing in the Green River, we're achieving greater economies of scale." The company is also taking the fracture-stimulation technology it has used to complete 600 tight-gas wells in East Texas and North Louisiana and applying that to optimize well flow rates in the Greater Green River. Easy gas, hard profits Out of its corporate headquarters in Denver, Tom Brown Inc. directs upstream operations in the Rockies, where it's currently producing an aggregate 140 million cubic feet per day of gas-22 million of that from the Greater Green River Basin. In Wyoming's Wind River Basin and Utah's Paradox Basin, it's producing a combined 85 million cubic feet of gas daily. Its assets there are more mature than those in the Green River, says James A. Honert, Tom Brown's Rocky Mountain exploration manager. "Also, in Colorado's Piceance Basin, the company is getting significant contribution from the White River Dome Field-the deepest coalbed-methane play in North America. "With the earlier-stage exploration and development drilling opportunities we've got in the Green River, we'd expect that basin a few years from now to make a more significant contribution to our growth in the Rockies," Honert says. With some 460 well interests in the Greater Green River, located mainly in the Moxa Arch and the Washakie and Red Desert basins, Tom Brown is ramping up its 2003 capex budget in the basin to $16 million from around $8 million last year. This will fund the drilling of 13 development wells and five exploration wells-the latter targeting mainly the 6,000- to 14,000-foot Almond and Lewis formations in the Washakie and Red Desert. So far this year, the company has already made an encouraging Washakie discovery. "We predicted the 14,000-foot well would encounter a gas-charged Lewis sandstone, and it did," says Honert. The well, which cost $2.2 million to drill and complete, is currently producing 6 million cubic feet per day of gas-1.5 million cubic feet net to Tom Brown. Currently, the company is evaluating offset locations. "It's easy to find gas in the Rocky Mountains, but it's hard to make money," says the Honert. "Rocks in this region give up their gas very sparingly over long periods of time; these are tough reservoirs-they're tight and highly impermeable. So you really need to get your drilling and completion techniques down to an exact science to manage costs." Clearly, the use of PDC bits and mud motors is helping the company drill faster and more cheaply. "There are fewer bit runs; therefore, it takes us less time to drill a well," says Dean Liley, northern asset manager, Rocky Mountain division, for Tom Brown. "At the same time, we're trying to make our completions more efficient. Halliburton recently introduced us to a new fracing technology that we're trying at our White River Dome Field. Very simply, it allows producers to do more [highly focused and cost-efficient] fracs over a shorter time." Honert points out that drilling and completion costs in the Greater Green River are averaging nearly $1 million per well. "However, we're on a path in the Rockies to reduce our drilling and completion costs, in many cases, up to 20%." With most of its Greater Green River gas now being sold at vastly improved Colorado Interstate Gas (CIG) Index prices-there were times a year ago when the company was getting only 90 cents per Mcf at the wellhead for the same gas-Tom Brown is optimistic about its increasingly economic growth through the drillbit in the basin. How much so? Jokes Honert, "We think this basin is a loser and that our competitors here ought to cut their losses, abandon it and leave it to us." Redirecting capital Back in 1995, amid then-depressed gas prices in the Rockies, Denver-based Forest Oil Corp. believed that over time there would be greater gas-takeaway capacity from the region, narrower basis differentials and higher gas prices. So it gradually began staking out its position in the front-range plays of the western sedimentary basin, in both Canada and the U.S. Today, it holds some 500,000 gross acres throughout that basin-more than 25% of that in the Greater Green River. However, with so much of its annual capital spending in the past two years aimed at bringing Alaskan oil onstream and streamlining its Gulf of Mexico operations, the company is just now beginning to aggressively drill up the Green River's potential. "We're really at the beginning of our program there, with interests in 39 wells and annual production of around 3.5 Bcf, primarily out of the 11,0000-foot Almond sands in the Wild Rose Field in the Washakie Basin and the 9,000-foot Lance formation in the Jonah Field-up to now our main areas of development," says Chip Oakes, Forest manager, geology and geophysics, western region. "But based on recent drilling successes at Wild Rose, we're now pursuing the Almond trend westward at West Wild Rose. Overall, we expect to drill and complete 26 Green River wells this year versus 14 last year-at a cost of $13 million." Daily output from the Green River's fields is relatively small-200,000 to 1 million cubic feet of gas per well-versus Forest's average companywide gas-production level of 1- to 2 million cubic feet per day per well," says Robert S. Boswell, chairman and chief executive officer. "But these plays are highly repeatable, with longer-lived reserves, lower finding costs and more consistent flow rates than is the case with the higher-return, but higher-decline-rate wells we have in the Gulf of Mexico. So the Green River is an excellent complement to our other operations and reflects our strategy of building a diverse portfolio of assets-much as an investor would do-with various levels of risk and returns." Says H. Craig Clark, Forest president and chief operating officer, "We came to the Green River because it's highly prospective, not as heavily drilled as the Permian or San Juan basins, and an analog to the type of drilling we're doing in the Canadian Rockies." Clark likes the fact that finding costs in the Green River average only $1 per Mcf versus $2 in the Gulf of Mexico. He also likes the fact that the company has managed to cut drilling costs 40%; last year they were as high as $800,000 per well. "We've accomplished this by using PDC bits as opposed to tricone bits; using better mud systems, which permit more extended periods of drilling, less rig downtime and less chance of formation damage; and bidding out multiple wells to contractors on a day-work basis," says Clark. "We've also been able to reduce completion costs by increasing competition among the service companies and improving frac technology. Today, we're fracing smaller zones versus fracing huge intervals. In short, we're increasing our reserves per unit of frac." Observes Boswell, "Drilling and completion costs used to run $1.5 million per well in the basin; now they're down to around $1 million." Diversified assets About one-third of Western Gas Resources' 1.2-million gross-acre Rockies position is in the Greater Green River Basin, principally in the Pinedale Anticline and Jonah Field to the south. There, it has nonoperated interests in 130 wells; in the Sand Wash Basin, it operates 10 more wells. "Collectively, the Pinedale and Jonah produce more than 975 million cubic feet of gas per day-almost half the Greater Green River's total 2.1 Bcf of daily gas production," says Dea. "Notably, our 22 million cubic feet of daily net production in the basin, mainly from these two areas, is 50% greater than in 2002-and we're looking for strong output growth this year." While Western Gas Resources participated in the drilling of 32 wells last year, principally with Questar, Ultra Petroleum and Shell in the Pinedale and Jonah, its drilling activity will be nearly double that this year. "The primary focus will be the Pinedale, where we'll be targeting the Lance and underlying Mesaverde formations at depths ranging from 13,000 to 14,000 feet," says Dea. These wells typically cost $4.2 million to drill and complete, and usually produce 6- to 7 Bcf of gas, he adds. Overall, the company has the ability to participate in 500-plus Pinedale well locations going forward, based on 40-acre spacing. "Here, we've got about a 10-year drilling inventory of very low-risk, high-return wells in highly prolific formations. In our view, daily output at Pinedale will probably double or triple as we tap into this monumental gas discovery. In fact, the ultimate combined recoverable reserves at Pinedale and Jonah could easily exceed 5 Tcf." Western, which is also drilling into 1.9 Tcf of unbooked, low-risk reserve potential in the coalbed-methane-rich Powder River Basin, isn't relying solely on the upstream to propel its economic fortunes in the Greater Green River. A major midstream player in that basin, it has a total of 1,434 miles of gathering lines in the Moxa Arch/Pinedale and Wamsutter areas that have the capacity to handle an aggregate 345 million cubic feet of gas per day currently-and as much as double that going forward by adding compression facilities. "We're truly an integrated gas company-from wellhead production through gathering, compression, processing and marketing," says Dea. "This means we can control our own destiny with timely well hookups to markets for ourselves and our partners-and profit from gathering, processing and marketing gas for other operators." Although highly diversified in its E&P operations throughout the onshore and offshore U.S., nearly 45% of Denver-based Westport Resources' 1.2-million gross-acre position in the Rockies is in the Greater Green River, where it currently has interests in 480 wells-450 in the Moxa Arch and another 30 in the Wamsutter Arch. Collectively, these wells produce 26 million cubic feet per day, mainly from the 10,000-foot Frontier and Dakota formations. "With natural gas prices much higher than what they were last year, that makes a big difference in our level of drilling activity in the basin's low-permeability, low porosity, tight-gas sands," says Don Wolf, Westport chairman and chief executive officer. "It wasn't that long ago in the region that we were getting $1 or less for our gas at the wellhead-and you can't drill $1 million wells based on that." This year, the company plans to drill 25 to 30 wells in its two main areas of development-about double the number of wells it drilled last year-spending on the order of $20 million. To be sure, Westport has a lot of elbow room to grow its Green River production, given that 80% of its total 524,000-gross-acre position in the Green River is undeveloped, exploratory acreage. This is in addition to the hundreds of development locations it has on its plate as the result of its $500-million-plus acquisition last December of El Paso Energy's gas properties in the Natural Buttes area of northeast Utah's Uintah Basin. Says Wolf, "Although we acquired 650 Bcf of proven gas reserves through the transaction, we believe there's another Tcf of gas-reserve potential out of the 6,500-foot Wasatch, the 9,500-foot Mesaverde and the 12,000-foot Mancos formations." The gas prospects the company is targeting in the Green River are in the 50- to 150-Bcf range. "Typically, these wells will start out producing 1- to 4 million cubic feet per day, then after a year, daily output falls off to 500,000 to 1 million cubic feet, then stabilizes at 200,000 to 400,000 cubic feet per day," he explains. "However, with improved gas prices, increased pipeline-takeway capacity and better drilling and completion technologies, the cost/return ratios per well are becoming more attractive." Wolf points out that during the past three years, the company has managed to reduce drilling and completion costs in the basin by about 15%. For one thing, the company is doing multi-stage fracs all at one time-opening up more net pay in a matter of a day or so-then producing all the zones back at the same time. "We're also making greater use of downhole mud motors," he says. "They allow us to rotate the drill string more slowly at the surface, which increases the life of the drill string and reduces failures. At the same time, they allow the drillbit to spin faster, improving the rate of penetration." Despite the huge undeveloped potential of the Greater Green River, Wolf isn't putting all his hydrocarbon eggs in one basket. "I believe in balance and optionality as to where we allocate capital. That's why we have gas drilling in the onshore Gulf Coast and Gulf of Mexico, as well as the Rockies." ROCKIES ROADBLOCKS In Wyoming's Green River Basin, as elsewhere in the Rockies, there are challenges ahead for independents that have nothing to do with drilling and completion technology, but everything to do with land access. Says one operator, "Because of the large amount of federal lands in the area, we're restricted as to when and if we can access them. In some cases, the restrictions are overdone." Here are some other industry takes on the issue. Roger Biemans, EnCana Oil & Gas (USA) Inc. We want to do further infill drilling in the Jonah Field because we believe there's the potential to double the production and ultimate gas-reserve recovery there-from 3- to 6 trillion cubic feet (Tcf). However, the Bureau of Land Management (BLM) has requested that we conduct yet another environmental impact study (EIS). That would be the fourth or fifth EIS done on this same, small-footprint, 25- to 30-square-mile area through the life of the wells. Up to now, working with the BLM and local officials, we've run into one roadblock after another. At the same time, gas prices continue to rise. None of this is going to help the national economy, Wyoming or the employment situation in the local counties. And the government isn't necessarily protecting the environment any better than if they were to work with the industry as a whole to allow for co-existence of our activities alongside nature. Mark L. Pease, Anadarko Petroleum Corp. The greatest challenge we face in the Rockies is increasingly lengthy permitting and approval processes just to drill. It wasn't that long ago when we could typically get our [drilling] permits in three months; now, in a lot of places, it's taking up to 10 months. And if an operator has to add a facility, that means additional permits and more waiting. The industry and the Bureau of Land Management (BLM) need to work together to make the permitting process more efficient. Robert S. Boswell, Forest Oil Corp. There are land-moratorium restrictions, seasonal restrictions and other difficulties in getting drilling permits. Two years ago, the typical lead time for getting a permit in some places in the Rockies was 85 days; today, it's 175 days. The industry has proved that it can go into [wilderness] areas and have minimal impact. But [the government] has created some artificial barriers-all with good intentions-that have suppressed the industry's gas-supply response and increased the cost of that commodity to the American public. Don Wolf, Westport Resources Corp. A recent report indicated that of the 4,200 drilling permits approved by the BLM last year, only 635 of them were processed within their target timeframe of 35 days. Generally, you now have to wait anywhere between 60 and 150 days to get a permit to drill a well. In Texas, you can get a drilling permit within a week.