When a resident of Chicago turns on his gas stove, chances are good that the molecules he burns have come from beneath the windy prairies of Wyoming. Far across the Continental Divide, people in sunny California might draw power for their air conditioners from plants fueled by gas that once resided beneath piñon scrub in northern New Mexico.

The story in natural gas supply today is the ascendancy of the Rocky Mountain region. The West has finally shouldered aside all other producing regions to become the major gas-supply powerhouse for the U.S. Production has skyrocketed from 10.2 billion cubic feet (Bcf) per day in 2000 to 13.6 Bcf in 2006, a quarter of all U.S. onshore gas production. And there are huge volumes of gas still to be recovered.

According to international consulting firm Wood Mackenzie, Rockies gas production has potential to grow to 17.2 Bcf per day in 2011. "This is a true upside number-it assumes that everything that is identified can be drilled, and that developments will deliver the same estimated ultimate recoveries as previous wells," says David Haas, Houston-based analyst within WoodMac's Lower 48 research group.

That number is still subject to the usual caveats of changes in price, regulation and costs.

Underpinning the production forecasts is steady reserve growth. During the past five years, proved gas reserves in the Rockies have swelled from 46- to 61 trillion cubic feet (Tcf), a 32% increase. Impressively, those additional reserves are on top of a total production volume of 21.6 Tcf during the same period.

The Greater Green River, Uinta-Piceance, Powder River and Raton are the basins that will deliver the lion's share of production growth going forward. Daily gas volumes from the Greater Green River could surge by 900 million cubic feet, driven by massive tight-sand projects in Pinedale, Jonah and Wamsutter fields. Further push could come from a fascinating new shale play in the Vermillion Basin and a coalbed-methane (CBM) play at Atlantic Rim.

Daily Uinta-Piceance production is expected to grow by 1.4 Bcf through 2011, thanks to the Piceance's Mesaverde tight-sand reservoirs and expansion of Natural Buttes Field in the Uinta Basin. WoodMac's drilling forecast for the Uinta alone is 8,500 total wells (both gas and oil) between now and 2011, says Haas.

Daily Powder River Basin gas volumes could rise 260 million, mainly due to the Big George CBM play, and the Raton Basin will post an impressive percentage increase as well.

And, the foundation for this sterling growth will be provided by the venerable San Juan, the most productive basin in the Rocky Mountain region and a steady producer of some 3.8 Bcf per day. "The fact that an area that is relatively mature is able to maintain production is a positive story itself," says Haas.

Most of the new Rockies gas will be exported to other parts of the country-only about 20% of the region's production stays in its home states. The scramble to move this abundance to markets will inevitably create bottlenecks and gas-on-gas competition for Rockies producers.

Resources Galore

The Greater Green River Basin, a complex of basins flung wide across southwestern Wyoming, is one of the region's most stalwart gas-producing engines. Encompassing the Green River, Washakie, Red Desert, Vermillion and Sand Wash basins, the Greater Green River is the site of mighty drilling programs that target tight sand, shale and CBM reservoirs. In the Pinedale, Hiawatha, Atlantic Rim and Moxa Arch areas, some 12,600 potential well locations are in various stages of the federal approval process.

Pinedale Anticline, in Sublette County, Wyoming, continues to be one of the amazing growth stories in North America, let alone the Rockies. The 90-square-mile field makes more than 900 million cubic feet of gas a day, and operators are on the cusp of what they hope is a major expansion.

Anticline operators are waiting on a record of decision (ROD) from the Bureau of Land Management (BLM) on their supplemental environmental impact statement (SEIS). Shell Exploration & Production Co., Questar Market Resources and Ultra Petroleum Corp. are promoting concentrated development of 4,400 wells. The scenario operators have proposed will cut development time for the giant gas field in half, reduce environmental impacts and leave more acreage open for wildlife. The ROD, which it is hoped will allow year-round drilling, may come in the fourth quarter.

Pinedale expansion is crucial to Houston-based Ultra Petroleum's growth plans. The anticline is the company's single largest asset, and one that has treated it very well. At present, Ultra produces 300 million per day net from its acreage at Pinedale (and neighboring Jonah Field), a volume that has grown stupendously from just 15 million per day in 2000. The company holds 33,000 gross acres across Pinedale, and 2,000 in Jonah.

"We're the largest operator in Pinedale, and we have interests across 70% of the field area," says Stephen Kneller, Denver-based vice president, exploration. "We're also the third-largest operator at Jonah."

This year, Ultra will continue to ramp up its production in the area, with a target of a 24% increase from 2006 results. Most of this will come from Pinedale, as Jonah volumes are projected to remain flat. The company will participate in 185 wells on the Anticline, of which it will operate about 80.

Pinedale is a unique and extraordinary field, a locus of a tremendous structure and fluvial deposits more than 5,000 feet thick. "The resource concentration at Pinedale is phenomenal," he says. "There is so much gas crammed into such a small place."

According to Netherland Sewell calculations made at year-end 2006, original gas in place at Pinedale was a whopping 48 Tcf. Ultra's proved reserves stood at 2 Tcf, and proved, probable and possible reserves were 10 Tcf net to the company. At five-acre density, total field recoveries could be an astonishing 27 Tcf.

Ultra's current Pinedale wells average 13,500 feet deep, reliably deliver about 7 Bcf equivalent (Bcfe) each and cost $6.8 million apiece. Typically the company runs some 25 frac stages per well across 5,600 feet of prospective interval in the Upper Cretaceous Lance pool. It uses about a million pounds of proppant and between 3- and 4 million gallons of fluid per completion. Its 146 wells that commenced production in 2006 flowed at average initial rates of 8.8 million cubic feet per day.

"Currently we have 12 rigs running, and Questar and Shell have another 12 running on leases in which we have an interest," says Kneller. Four Ultra-operated rigs are drilling delineation wells, one is turning to the right on a deep test, and the rest are working on pads on increased-density projects.

Pad drilling has revolutionized Pinedale development. Currently, the company is drilling up to 16 wells at 10-acre spacing on a single pad; at five-acre spacing, 32 wells could be accommodated. Ultra can simultaneously drill, frac and complete wells on the 18-acre pads. For production operations, pads can be quickly reclaimed to just a handful of acres.

The concentrated activity has continued to spawn new efficiencies. "From 2006 to the first part of this year, we've reduced our drilling time from 60 days to about 40 days a well, with some of the rigs now able to drill in less than 30 days," says Kneller.

The company will be busy for years to come at Pinedale. Ultra has 5,000-plus locations at five-acre spacing that could recover an average of 4.6 Bcfe each on its acreage position, enough for more than 25 years of steady drilling at current activity levels.

If the ROD for the Pinedale SEIS is issued sometime this fall, that development could take place much more rapidly. If the ROD is delayed, however, Ultra can move rigs south on the anticline and drill through winter. "Two-thirds of our operated lands are in areas with winter stipulations, but we do have enough opportunities to keep our rigs busy."

And, there could be more. Ultra is also at work on a deep test at Pinedale. Last year, the company spudded its Mesa #10D-33 well, projected to 19,500 feet. The test, which should reach total depth this fall, will evaluate Hillard and Blair objectives. The Hillard shale is viewed as the dominant source rock for Pinedale and Jonah, and an earlier deep well flowed gas at strong rates from Hillard before it encountered mechanical problems. The Blair is a low-porosity, low-permeability sand interval that could have larger areal extent and higher pressures than the Lance, notes Kneller.

"We have possibilities for potentially significant production, but it will be many months before we have results."

Success in deep intervals would mandate new calculations of Pinedale resources, obviously. Numbers that are already too large to fully grasp will grow further.

Tight Sands, Shales

A Rockies-centric company that is doing its part to raise production levels across its million acres in the region is Questar Market Resources Inc. This firm, based in Salt Lake City, operates throughout Western basins, and also has substantial assets in the Midcontinent.

Questar's largest producing area is Pinedale, and it's in the midst of a long-term plan on the anticline. "We're right on schedule at Pinedale, and we're happy with the way it's going," says Paul Matheny, Questar's Denver-based vice president, Rockies region. "If the SEIS is approved in a form that resembles what we have proposed, we'll enjoy an accelerated pace of development."

At present, Questar has 215 producing wells on Pinedale's northern end making some 255 million cubic feet of gross gas per day. "We have a little bit shut-in, because of low prices," he says. "Our capacity is about 330 million, and that's growing every day."

In Questar's area, an average 14,300-foot directionally drilled well costs $5.8 million, completed. "We've evolved our completion techniques, and today we do 15 to 16 frac stages per well." An initial well recovers in the range of 8 Bcfe, and increased density wells are modeled to recover less, depending on specific circumstances.

The company currently has seven rigs working. This year, it expects to complete around 50 wells. By 2010, depending on the BLM decision, the company could be drilling more than 100 wells a year on its operated acreage. That would have considerable impact on its production growth from the anticline, because Questar has an inventory of more than 700 wells to drill at 10-acre spacing. On a mix of five- and 10-acre spacing, that figure rises to 1,200 potential locations.

In another corner of the Greater Green River complex of provinces, Questar has an emerging shale-gas play under way. The Vermillion Basin straddles the Wyoming/Colorado border and is home to notable fields found on surface structures between 50 and 80 years ago.

The company has worked the area since its discovery of Hiawatha Field in 1927. "It's been our backyard for a long time," says Matheny. These early fields mainly produced from Cretaceous Mesaverde and shallower intervals. Successful deep drilling in the 1980s at Hiawatha established gas production in Jurassic Nugget.

The 21st century has brought a new turn of events to the area. The deep Nugget tests had yielded interesting gas shows in the Baxter, a 3,500-foot-thick, overpressured Cretaceous shale that lies above the Frontier. "We knew the interval was gassy, but we couldn't produce it with technology available at the time."

That's changed today, with the revolution in shale-gas methods and techniques that has swept from the Fort Worth Basin throughout the country. During the past two years, Questar has drilled 16 vertical wells and a horizontal well on its 146,000 net acres of Vermillion leasehold.

"Some of our results have been spectacular and some have been mediocre," says Matheny. Questar's Trail #13-C well was one of the spectacular ones. The well, a vertical test on the flank of the Trail structure in the northern part of its acreage, made 530 million cubic feet of gas in its first 70 days on production. "We believe that we encountered a well-developed natural fracture system, and we've tried to calibrate that to our regional 3-D seismic data and understand what characteristics that area had that we could exploit elsewhere."

The most effective way to accomplish this might be with horizontal wells. Questar recently completed Canyon Creek #79H, on the flank of the Canyon Creek structure. That well produced 5 million per day in its first five days online, from 1,000 feet of lateral hole. The company cased and cemented the lateral and pumped four frac stages. It is now drilling its second horizontal well.

"We're in the very early stages in this play, and we're testing our ideas," he says. "For the immediate future, we expect to keep one rig at work there. There's an astonishing amount of gas out there for us to try and recover."

Questar is also keeping its shoulder to the wheel to raise production in the Uinta Basin. The company has a major play in Uintah County, Utah, just north of Natural Buttes in Red Wash and Wonsits Valley fields. At present, it produces about 100 million cubic feet per day gross from its 120,000 net Uinta acres. This year, it plans 60 to 70 wells.

Although the company still has 40-acre development locations across its leasehold for Wasatch and Mesaverde reservoirs, it is quite interested in the Mancos, a shale time-equivalent to the Baxter in the Vermillion Basin, and in the Dakota sandstone.

"This year, we have shifted our Uinta program to drill deeper Mancos and Dakota tests," he says. A Dakota well can reach depths of up to 17,000 feet, and cost in the $7-million range. Only a few have been drilled in the basin to date, and Questar is distributing its deep tests across a wide swath of its acreage. At present, the company has four deep rigs working the basin.

In the Dakota, Questar recently completed a well that came onstream at 6.5 million per day natural. "This is exploration drilling. But at the same time, there are so many pay zones in our fields that we know we can make a gas well in the shallower section. It gives us confidence to do deeper drilling."

Company-wide, Questar expects to produce between 135 and 138 Bcfe in 2007, a sturdy increase from 2006 production of 129.6 Bcfe. "We have a huge acreage position in the Rockies. Our challenges are to get it all evaluated and keep our eye out for new things," says Matheny. "We have lots of good projects.

Huge CBM Project

Although the Greater Green River has not been known as a major CBM province, this could change with development of Atlantic Rim. This long-talked-about prospect lies along the east side of the Washakie Basin, just updip of prodigious Wamsutter Field. The Carbon County, Wyoming, project stretches 40 miles long by 10 miles wide along the basin's hingeline, bringing Cretaceous Almond and Allen Ridge coals within easy reach of drillbits.

Denver independent Double Eagle Petroleum has been working Atlantic Rim since 1999, when it launched the play with a recompletion of an existing well in Cow Creek Field in Almond coals. Today, the company holds more than 50,000 gross (30,000 net) acres in the project area.

The objective coals at Cow Creek are found in the top 400 feet of the Cretaceous Mesaverde at depths from 1,000 to 1,400 feet. Seams are between one and 20 feet thick, and wells have 20 to 30 gross feet of coal. Gas contents are excellent, in a range of 200 to 300 standard cubic feet (scf) per ton.

As attractive as Atlantic Rim appeared when first discovered, development has been delayed numerous times. This is a highly sensitive area, and federal approvals have taken five years so far. In 2002, the BLM decided to allow up to 200 wells to be drilled in 24-well pods while the EIS was being prepared.

In June, Atlantic Rim operators finally received a ROD from the BLM that will allow them to drill 1,800 CBM and 200 deeper conventional wells.

Not surprisingly, several groups immediately appealed the long-awaited decision, and the Internal Bureau of Land Affairs is currently reviewing a request for a stay of the decision. Field operators have agreed to hold off drilling operations until August 6. (Depending on IBLA findings, the project could potentially be delayed again.)

But as soon as operators get a green light, they are ready to move forward. That's because results from pilots, particularly those in the center of the area, have been strongly encouraging.

Double Eagle's main producing asset in Atlantic Rim is its 21,000-acre Catalina Unit, on which it operates 14 wells in a pilot at Cow Creek Field. In 2002, the company drilled and fracture stimulated most of its wells, which immediately began making gas at rates of about 200,000 cubic feet a day apiece. After 18 months, the wells reached a production plateau at average rates of 450,000 per day each. Today, the field makes 6 million a day. "The wells have really held up nicely for us," says Steve Hollis, chief executive officer.

Double Eagle also owns 20% interest in another 46 wells that Anadarko Petroleum operates in a pilot at Doty Mountain, and 4.5% interest in 12 wells at Warren Resources' Sun Dog pilot.

Infrastructure development in the remote area is in its infancy, to say the least. For the past eight years, Double Eagle has had to generate its own electricity onsite. That's supposed to change in August, when the power company will finally hook Cow Creek to the grid. To access gas markets, Double Eagle also had to lay its own 13-mile pipeline.

If Double Eagle's program can proceed as planned, it will bring in two to three rigs to drill 34 wells in Catalina Unit this year. About 10 of those could be producing before the close of 2007; the remainder would be pumping in first-quarter 2008. Well costs are about $1 million apiece, and reserves are 1 to 1.2 Bcf per well.

"I think that we are off and running, and we're finally going to find out if this will be a major field or not," says Hollis.

Warren Resources has also been working Atlantic Rim for years. In 1999, the New York-based company purchased a huge leasehold position from Stone & Wolf and Tower Columbia, the original operators.

Warren and Anadarko Petroleum agreed to a joint venture at Atlantic Rim in late 2002, giving each company 141,000 gross and 70,500 net acres. Warren and Anadarko, project operator, have now drilled more than 120 wells in several pilot areas.

The oldest is 21,000-acre Sun Dog pilot, just east of Double Eagle's Catalina Unit. Here the partners drilled 12 pilot wells that were completed naturally and have been steadily inclining to present rates of 450,000 cubic feet per day per well. This year, Warren and Anadarko expect to drill 70 wells in Sun Dog.

Doty Mountain, north of Sun Dog, has 46 producing wells on 80-acre spacing, 22 of which were drilled in 2006. The first group of wells is making about 1.8 million per day and 7,800 barrels of water; the second group was recently put on pump.

Another pilot, Blue Sky Unit, is a 24-well pod that was initially drilled on 160-acre spacing and recently infilled to 80 acres. At year-end 2006, Blue Sky was still in its dewatering stage. Red Rim and Jolly Roger, pilots that contain 16 and 24 wells, respectively, were both drilled on 160-acre spacing and are also dewatering.

"This year, we plan to drill wells that connect Sun Dog, Doty, Blue Sky and Catalina," says Ken Gobble, president and chief operating officer of Warren E&P Inc., the Casper-based operating subsidiary of Warren Resources. "We will create a big pressure sink, which should really help production." Other work in 2007 will be directed at adding infrastructure for 2008 activity.

"In our view, the coal in Atlantic Rim is one of the most productive coals for CBM production in the Western U.S.," says Canaccord Adams analyst Irene Haas, based in Houston. Favorable features of the play include its short dewatering time, dry gas production, high permeability and high gas content of its coals. In-place resources are calculated at 8 Tcf; as much as 4 Tcf could potentially be recoverable across the entire play.

Big George and More

A separate sort of CBM development will bring strong production growth to the Powder River Basin. More than 17,000 CBM wells in the Powder River currently produce nearly 1.2 Bcf a day, and development of the Big George coal is driving rising volumes.

One operator alone, The Williams Cos. Inc., holds a million gross acres in the basin and has 8,500 drilling locations (50% operated) in the Big George play.

Perhaps the most impressive Big George success story is the County Line project, and a pioneer of the play is small Casper-based independent North Finn LLC.

In the mid-1990s, just as Wyodak production was being established, North Finn, owned by brothers Wayne and Mike Neumiller, started to work the CBM play as a drilling contractor. "We were always an operator, so we were much more interested in our own prospects than in the service side," says Wayne Neumiller. North Finn soon teamed with Bill Strickler, president of Mount Pleasant, Michigan-based Michiwest Energy Inc., and Casper consulting geologist Ron Baugh.

In 1998, North Finn and Michiwest took a 27,000-acre farm-out from Anadarko Petroleum to test the potential of the Big George, a very thick Fort Union coal that had never produced commercially in the Powder River Basin. The partners committed to drill 14 closely spaced wells on 320 acres at the junction of Johnson and Campbell counties. After the partners successfully demonstrated commercial potential in the Big George, they would earn a 50% interest in the leasehold.

The 1,100- to 1,400-foot wells were drilled by the spring of 1999, and the partners began to pump water. Many of the wells pumped 3,000 barrels or more per day, and for months the project produced only water. "It was quite the battle," says Neumiller. "There was no electricity out there, so all of the wells were powered by generators. Half of the wells were actually artesian wells out of the Big George coal. It was really hard to keep the submersible pumps running consistently."

Finally, after 15 to 18 months of dewatering, gas began to flow at encouraging rates. "Nobody in Wyoming believed this was going to work. We were told numerous times that we were making a mistake and wasting our money and our time."

They got it to work, nonetheless. North Finn and Michiwest started to drill additional wells, and negotiated a 19-mile pipeline connection to the project. "When we first started working there in 1998, the closest pipeline that would take CBM was 50 miles away." Indeed, Anadarko liked the partners' project so well that it took over operations, as per its farm-out contract.

"We were happy about this, because of the tremendous amount of people and resources that CBM requires. Anadarko has solved all of the big problems out there." One rancher quite resistant to development was bought out, and Anadarko constructed a pipeline that takes much of County Line's produced water to its Salt Creek Field, where it is reinjected. The company also negotiated firm pipeline space to move County Line's gas to market.

Under Anadarko's operatorship, drilling took off. In January 2007, the project was fully developed with 418 wells. Today, an average well at County Line is about 1,400 feet deep and taps some 140 feet of coal in a single seam. Gas contents average 75 to 80 scf per ton, and in-place resources are 1.6 Bcf per 80-acre unit.

County Line's current production is 150 million cubic feet per day, coming out of fewer than half the completed wells. Average daily production is 700,000 cubic feet per well. "We're constrained right now by pipelines and compressors, and we expect production to rise significantly once those are relieved," says Neumiller.

Building on its success in its Big George venture, North Finn is also in the forefront of another developing gas play in the historically oily Powder River Basin.

North Finn is operator of record and owner of 7.5% working interest on the 56,000-acre Fetter project in Converse County. The remaining 92.5% interest is held by Denver-based American Oil & Gas Inc. Fetter is the eastern portion of a larger 128,000-acre position that the companies amassed that targeted stacked pays along the southern edge of the basin. Fetter's potential had been recognized for years, but the area posed some formidable issues.

"Our main objective is the Frontier formation at 11,500 feet," says Andy Calerich, American's president. "The reservoir is overpressured, and we've drilled a couple of wells before with strong geologic success, but it's been very challenging from an engineering standpoint."

To address the technical problems, North Finn and American struck a farm-out deal on the Fetter acreage with Red Technology Alliance LLC last year. RTA agreed to fund a three- to four-well drilling program to earn 75% in the earning wells and 25% in the undrilled acreage. Halliburton Energy Services is acting as project manager.

The addition of RTA has brought success. The partners recently announced completion of the first well in the venture, Sims #15-26H. It was drilled underbalanced to a total measured depth of 12,840 feet, which included a horizontal leg of 1,165 feet in the Frontier. During drilling operations, it flowed at rates of greater than 20 million cubic feet per day. The companies were able to install a liner in the hole and were expecting at press time to hook the well up to sales shortly.

Next up at Fetter could be a reentry of a 2005 well that was temporarily abandoned for mechanical issues. The partners may attempt a horizontal leg in the Frontier at this site. Also on the drawing board are plans for a vertical well, to test potentials in the Steele, Niobrara, Frontier, Mowry and Dakota formations.

Recently, American and North Finn expanded their relationship with RTA. In early July, the companies entered a farm-out agreement under which RTA will drill and complete a deep test to earn a 50% working interest in American and North Finn's 40,000-acre West Douglas acreage block, adjacent to and west of Fetter.

Raton Contribution

One more area projected for strong production growth is the Raton Basin. This is a novel basin that's almost exclusively a CBM-producing province. It sits in southern Colorado and northern New Mexico, to the east of its famous cousin-the San Juan.

El Paso E&P Co. holds 605,000 net mineral acres in the Raton, mainly in Vermejo Park Ranch in Colfax County, New Mexico. The company acquired a 50% interest in minerals under the ranch in the late 1990s and began a joint development of the property with Devon Energy Corp.

"The New Mexico portion of the Raton Basin was basically stranded," says Bill Griffin, Houston-based senior vice president, onshore division. "As part of our entry, we connected New Mexico to El Paso's CIG pipeline system in Colorado. Then we began to develop the property." In 2002, El Paso bought out Devon's interest.

From a dead start in 1999, El Paso now produces 77 million net cubic feet a day from some 800 wells in the basin. And, the Raton has an enviable location in the southern Rockies, so its gas enjoys basis differentials close to Midcontinent norms.

This year, the company is accelerating its Raton activity to nearly double its previous levels: it expects to spend $113 million to drill 184 wells, a sharp jump from the 100 wells a year it had been drilling.

The company inherited a good bit of core data when it acquired Vermejo Ranch's mineral estate, and it focused its initial drilling on more prolific areas. "In the past, we focused on two to three core areas of operations, and we used an onion-skin approach to expand those areas. Now, we're drilling pods of wells and bringing them on in groups."

The company is running one to two rigs at present. Wells range from 2,000 to 2,500 feet in depth, and spud-to-rig-release is 36 hours. Drilling comprises a relatively small percent of total costs, as the bulk of capital goes for roads, locations, power, facilities and completions. So far this year, El Paso has been able to drive average well and facilities costs back down to below $600,000 apiece.

Typical reserves are 450- to 750 million cubic feet per 160-acre well, and production rates average 100,000 to 200,000 cubic feet per day. Gas flows from two primary seams: Raton and Vermejo. Production is commingled, all of the wells are foam fraced and all produced water is injected into subsurface disposal wells. The coals produce minimal water, and peak rates are often seen during the first few months of production.

In a new development, the company is drilling sidetracks from existing vertical wells to test horizontal recoveries. "Vertical wells effectively drain 160 acres in some areas, but in others they do not. We haven't decided yet whether infill or horizontal drilling is the best approach to capture those bypassed reserves."

El Paso still has plenty of expansion opportunities on its leasehold position. "Economic limits in the CBM world move with gas prices, so if we can get well costs down or prices improve, we can develop thinner or shallower coals," says Griffin.

"There's a lot of development left to occur. We've had steady production growth, and we expect to continue our success."

Challenges Abound

For all of the gas projects on the books and new gas production bursting out of the Rockies, there are of course attendant problems.

One of the most distressing, especially for Northern Rockies operators, is the huge basis differentials. At present, producers are suffering discounts of more than $3 per thousand cubic feet of gas. That basis should narrow considerably next year when the 750-mile leg of Rockies Express pipeline is completed from eastern Wyoming to Missouri, and shrink further when the Missouri-to-Ohio portion is finished in 2009.

However, differentials are a complex topic. Distinctions have to be made between short-run and long-run, and between correlation between intra-region hubs and deviation from Henry Hub, says WoodMac's Haas. That's because differential trends are neither sustainable nor consistent.

"With regard to short-run prices, conventional wisdom today is that Rockies differentials are driven by the construction, commitments and nominations for Rockies Express," he says. That's certainly the major factor, but it is not the only influence.

During the past three to four years, staggering piles of hedge-fund money have poured into the trading markets, specifically Henry Hub. This money is speculative, and has dramatically contributed to price volatility.

The question is: How much of the spread is due to artificial movements in price, and how much is due to such nuts-and-bolts issues as capacity constraints? "It's possible that Henry Hub prices are pulling away from local hubs, and the addition of Rockies Express capacity may provide less relief than operators in the region expect," Haas says.

Regardless of the mechanics of differentials, Rockies producers have hedged a good portion of their production at prices well above not only differential, but also above current Henry Hub prices. That has insulated chunks of production from basis problems. "There certainly is a lot of wringing of hands because of the differentials, but we haven't seen many significant changes in development plans and capital commitments." (For more on Rockies differentials, see "Rockies Waiting Game" in this issue.)

Another troublesome Rockies issue is strong demand for people, rigs and equipment. The thousands of wells that are slated to be drilled in existing and new development areas will further strain the industry's already stretched capabilities in the relatively remote and lightly populated Western states.

Finally, there's the constant bugaboo of federal, state and local regulations that faces operators. Sage grouse mating, elk calving, black-footed ferret habitat, air pollution, noise abatement, water disposal and many other concerns occupy office staff, field personnel and veritable armies of specialized consultants.

Resistance to large-scale gas developments appears to be growing, and industry is scrambling to alleviate community concerns. Operators know that gas can be extracted in ways that are both environmentally friendly and economically beneficial, and they are striving hard to get that message to citizens of the West.

But, as anyone who has survived one of the brutal bust cycles knows, these are good kinds of problems to have. The Rockies are stuffed with gas, and lots of companies are dedicated to getting that gas from the ground and sending it East and West.

Multi-Tcf Potential

One firm that has added a substantial Rockies position to its portfolio is privately held Redwine Resources Inc. The Dallas-based independent launched its efforts in the Rockies four years ago, and has already amassed 250,000 acres in several high-impact prospect areas.

The Rockies' wide-open spaces and available land positions and exploration projects attracted the company, which has operated in South Texas and Oklahoma for more than 20 years. "When I started looking in the Rockies, I felt that the region was going to get more parity on prices sometime soon," says Gary Redwine, president. "Since then, lots of gas-transport projects have been announced."

Redwine is well familiar with CBM, as it operates 250 such wells in the Midcontinent's Arkoma Basin. The Rockies' Atlantic Rim offered it just the right opportunity, and the company entered the play in 2004. It picked up acreage from several different companies and landowners, and assembled an impressive block in the heart of the play. Late last summer, it started drilling there and is now hooking up a five-well pod. "We control about 20,000 acres in Atlantic Rim, and if successful we could have a 100-billion-cubic-foot project," says Redwine.

In the Sand Wash portion of the Greater Green River Basin, the company has developed a 50,000-acre project. "This one's a basin extension, and we hope to have a 2- to 4-trillion-cubic-foot (Tcf) field in Lance and Fox Hills," he says. The stratigraphic play lies about 10 miles south of Powder Wash Field in Moffat County, Colorado.

Redwine's other Rockies ventures include a 70,000-acre Paradox Basin structural prospect with multi-Tcf potential in Montrose County, Colorado; a Big Horn Basin project that targets Muddy and Frontier reservoirs in the 20- to 30-Bcf range near Meteetsee Field in Park County, Wyoming; and a prospect in Lake Basin in Golden Valley, Montana.

The company is in the Rockies for the long haul, and it's been earning its stripes with federal regulators. "It's been slow to get some of these large projects developed," says Redwine. "We've had delays, and we've had to learn the ins and outs of dealing with the Bureau of Land Management, but we've been warmly received and it's working out well."

Redwine opened a Denver office last summer, led by exploration manager John Blair and engineering manager Dick Pate. "We have an exciting drilling season coming up, and hopefully we will have some success."

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