The Rocky Mountain region offers the energy business a big—but sometimes overlooked—target for new reserves. Despite the industry's current focus on such shale plays as the Bakken, Marcellus and Eagle Ford, the Rockies contain attractive, multiple conventional and resource prospects along and on either side of the mountains.

The Niobrara shale currently generates the most activity, and it may do so for quite awhile, say midstream operators who know the Rockies well.

"Sprawling" describes a key business point the midstream must consider: The region's oil and gas plays spread over many miles and—even when there is some infrastructure in place—it may be miles away. That creates great opportunities for midstream growth.

Limited transportation options and markets traditionally have kept prices to producers low, relative to other regions. But that's changing as the region's production grows and transportation infrastructure improves, operators add.

Niobrara now

The Rockies play that creates the most buzz now is the Niobrara, which first proved itself an attractive target for horizontal drilling and hydraulic fracturing in the Denver-Julesburg basin, or "DJ basin," of Colorado to the north and east of Denver. But like most other things in this part of the world, the Niobrara—a conventional producer for years—extends a long ways. It runs northward from the DJ basin into Wyoming and Nebraska, eastward into Kansas, beneath Colorado's Piceance basin on the Rockies' Western Slope and bumps up against eastern Utah's Wasatch and Uinta ranges.

Exploring the play's potential in that wide swath will take years, not to mention the potential of other Rockies resource plays, such as the Mancos shale. Key for drillers right now is proving the Niobrara's potential elsewhere outside of the DJ, and initial results appear positive.

The region's overall drilling rates in 2012 will rank historically high but below the record pace set several years ago before the energy oil and gas price collapse in late 2008.

The brisk drilling rate in recent years can be measured in growing hydrocarbon output. Colorado's crude oil production surged by nearly two-thirds from 2007 to 2011 and natural gas output rose a healthy 27%, according to the Colorado Oil & Gas Conservation Commission. This year's drilling permit applications to the commission, through mid-October, were historically high but lower than a busy 2011.

Next door, Utah's Division of Oil, Gas and Mining had 1,543 drilling permit applications through mid-October, compared with 1,515 for all 12 months of 2011.

Rockies plays have seen a growing use of horizontal drilling coupled with multi-stage fracture treatments. A benchmark of that familiar industry trend comes in statistics gathered by the Wyoming Oil & Gas Conservation Commission: In 2011, Wyoming saw 830 wells receive 10,186 individual stimulations, or a little more than 12 per well. Five years earlier, the state's average stimulated well received a four-stage fracture treatment. Some wells now see 20-stage treatments.

All those new wells create midstream opportunities to move the produced oil, gas and natural gas liquids (NGLs) to market. And those markets, in the case of the Rockies, usually are a long ways away. The region's abundant resource potential lies beneath a thin population with only two major metropolitan areas, Denver and Salt Lake City, close at hand. Big refining and processing markets on the West Coast, the Gulf of Mexico or in the Midwest lie 1,000 miles away.

Not a newcomer

The currently hot Niobrara is hardly a newcomer to the Rockies energy scene. The formation sourced Colorado's first oil well drilled in 1881, according to Stephen Sonnenberg with the department of geology and geological engineering at the Colorado School of Mines.

But as with other recent successful resource plays, a single well caught the industry's eye. In early 2010, EOG Resources reported its Jake 2-01H in Weld County, Colorado, had initial production of 1,558 barrels (bbl.) per day of oil and 350,000 cubic feet (Mcf) per day of gas. The well flowed 50,000 bbl. of oil in its first 90 days on production. Right behind that well, Noble Energy Inc. announced its Gemini well, also in Weld County, produced 60,000 bbl. of oil equivalent in 60 days.

Those numbers set off a leasing stampede in the area and a brisk drilling pace since. As with other shale plays, horizontal drilling and hydraulic fracturing combine to make what had been a ho-hum conventional play a keeper. Midstream operators have had to scramble to keep up with the production.

But Niobrara geology varies, more than some other shale plays that trend with little difference in geology, mile after mile. Well siting must be more exacting than with some other active resource plays.

"It's spotty, it's extremely variable," Mike Kelly, analyst with Global Hunter Securities in Houston, tells Midstream Business. He recently did estimates on the potential financial returns of 28 horizontal oil plays in North America.

But when the Niobrara's good it's very good, adds Kelly. In his report, he estimates the Niobrara's Wattenberg Extension play in Weld County, has a potential internal rate of return (IRR) approaching 70% based on assumptions of $90 per bbl. for oil and $4.50 per Mcf for gas, the second best IRR among the plays he studied, behind the Mississippian-Nemaha Ridge in Oklahoma and Kansas.

"Honestly, it's just hard to beat but it doesn't have the areal extent of some other plays," Kelly adds of the Wattenberg Extension. He says the play's great economics are helped because it is comparatively shallow and the overlying formations easy to drill. Fracture-stimulated horizontal wells can be drilled and completed quickly. That keeps costs low, in the $4 million-per-well range.

He estimates the broader Wattenberg play with the DJ basin has a potential 50% IRR, still well ahead of the 42% average IRR for all of the horizontal plays he reviewed. "We feel that in most instances a 25% IRR is necessary to justify drilling, as the calculation isolates drilling and completion costs—single-well economics— and doesn't include the very tangible costs of leasing, seismic and general and administrative expense that are incurred at the corporate level," Kelly says in his study.

Kelly mentions current major Wattenberg drillers include Noble Energy, Anadarko Petroleum and PDC Energy. The Niobrara's strong production rates and attractive reserve potential in the DJ have garnered recent attention from overseas producers along with North American operators, similar to what's happening in the Eagle Ford and other active shale plays. Carrizo Oil & Gas in October announced a joint venture with Oil India Ltd. and Indian Oil Corp. Ltd. to develop Carrizo's acreage in Weld and Adams counties of Colorado.

DJ's midstream

Several midstream players currently are responding to the brisk Niobrara-focused activity in northeastern Colorado, and DCP Midstream ranks as one of the bigger firms. Wouter van Kempen, president and chief operating officer, says DCP's focus there goes back a couple of years.

"Around the 2010 time period, we embarked on a strategy focused around our footprint," van Kempen tells Midstream Business. "What we expected is that people would move into liquids-rich drilling, away from the dryer gas areas. That is what has happened."

DCP currently has a DJ basin gas processing capacity of a little more than 400 million cubic feet (MMcf) per day. "We put the new Mewbourn plant online last year. We thought it was going to take us three to four years to fill that plant up. We ended up filling it up in six months. There's a tremendous amount of activity going on in the DJ," he adds.

Now DCP has construction under way on its LaSalle plant, expected to come online in the second half of 2013, adding an additional 160 MMcf per day of processing capacity.

"I think we're going to be in exactly the same position as with Mewbourn. It's going to be another plant that we're probably going to fill up in a matter of months versus a matter of years," van Kempen says.

DCP has started permitting its new Lucerne plant, which will have a 200 MMcf per day capacity, and expects it to go online in the middle of 2014. "Given how things are going, we think that that plant is going to fill up fairly quickly as well. We're looking at 2015 right now, and what it is that we need to do to continue to put additional capacity in the area," he says, adding DCP alone, could have more than 1 billion cubic feet (Bcf) per day of processing capacity by the end of 2015.

Another midstream beneficiary of the DJ basin drilling uptick has been White Cliffs Pipeline LP, David Minielly, the firm's vice president of operations, tells Midstream Business. Construction began on the 12-inch, 527-mile pipeline from Platteville, Colorado, to Cushing, Oklahoma, in 2008—while DJ basin producers were focused on conventional Wattenberg gas production. The system moves crude oil and condensate to the Cushing hub and entered service in 2009.

Right place-right time

"What they were primarily looking for was flow-assurance for their gas wells," Minielly says. "At that time, gas prices were close to an all-time high. In order to keep the gas flowing, they had to keep the condensate lift." Local markets proved limited, primarily the 90,000 bbl. per day Suncor Energy refinery at Commerce City, Colorado, that serves the Denver metropolitan area. The line to the Cushing hub provided multiple new markets and more attractive pricing, he adds.

Then the liquids-rich Niobrara hit. White Cliffs' anchor customers, Anadarko and Noble, are among the most active drillers in the area.

Thanks to additional, DJ basin and Niobrara-focused horizontal drilling, "they are producing a lot more liquids than they were in the past," Minielly says. From initial flow rates around 20,000 bbl. per day in 2009, the pipeline now runs close to its 70,000 bbl. per day capacity. The firm announced an open season in September for a looping project that will provide an additional 80,000 bbl. per day of capacity in the first half of 2014. White Cliffs' affiliate, Rose Rock Midstream LP, operates the pipeline and a 10-bay truck rack in Weld County, currently under expansion to 16 bays.

"There has been consistent growth in the DJ basin and fortunately we have been a recipient of a lot of that growth," Minielly says. In addition to White Cliffs' expansion, planning is under way with Noble for Rose Rock to construct, own and operate a 37-mile, 12-inch Wattenberg Oil Trunkline running north from Platteville and a new rack, "so they won't have to truck their barrels as far, and they could hook up their gathering systems to that line." Anadarko recently connected their gathering system to Rose Rock's facility at Platteville, "so their volume also continues to grow."

Storage expansion

New gas storage complements the area's growing midstream infrastructure—an important addition to the Cheyenne gas hub, located just inside Colorado south of the Wyoming capital. Colorado Interstate Gas Pipeline administers the hub.

East Cheyenne Gas Storage LLC (ECGS), a natural gas storage project built in Logan County, Colorado, by Merchant Energy Holdings LLC, opened in December 2011. East Cheyenne uses two, nearly depleted oil and gas reservoirs, West Peetz and Lewis Creek. The West Peetz storage area has a working gas inventory of 11.5 Bcf, and the Lewis Creek storage area has a working inventory of 7.4 Bcf. The project connects to the Trailblazer pipeline, which provides ready access to the Cheyenne hub. Merchant Energy is evaluating additional interconnects with other systems.

The project has performed well and Phase 2 is now under way, Ron Richards, senior vice president of engineering and operations, tells Midstream Business.

"The commencement of Phase 2 construction is a real milestone for us," says Richards. "The reservoir is performing very well and, as such, we are able to deliver the operations and services demanded by the region. With the future development of the adjacent Lewis Creek field, ECGS and partner, Quantum Energy Partners, will be able to add additional high deliverability capacity and meet the growing needs for storage in the Front Range market and at the Cheyenne hub."

ECGS will have approximately 8 Bcf of working gas capacity for the upcoming storage season with Phase 2 increasing working gas capacity to 14 Bcf and an increase in injection and withdrawal capacity to 230,000 dekatherms per day. Completion is scheduled for 2014.

East side, west side

Compared to the DJ basin and the bustling east side of the Rockies, current drilling west of the mountains might be called steady. Colorado's Piceance and Sand Wash Basins, Wyoming's Green River Basin and Pinedale Anticline, and Utah's Uinta basin have good activity but there's no land rush—yet.

The Niobrara lies beneath this region, too, but exploration of its local potential trails well behind the DJ Basin. Meanwhile, the Western Slope has other formations with good NGL production. The Mesaverde, for example, has been a stable gas producer for years.

To the south, the emerging Mancos shale may prove to be yet another exciting resource play. It extends from the southern reaches of the Piceance into the Four Corners region.

The Williams Cos. is a key midstream player west of the Rockies. In Wyoming, it's Opal and the Echo Springs processing plants handle production coming out of the Green River Basin and the Pinedale Anticline. Active drillers include Shell, Ultra, Encana, BP and Anadarko. The Wyoming fields tend to have drier gas streams than many shale plays but the area remains active.

"Drilling has subsided, natural gas prices being what they are. The competition for capital dollars has risen with the onset of the shale plays," says Dan Kalan, Williams' manager of commercial development for Southwest Wyoming. "But the emergence of the Niobrara in the DJ basin and other shale plays to the east have had an impact on where the region's gas goes to market," he tells Midstream Business.

"The shale plays are shifting gas markets. They're moving gas from the east back to the west. But in spite of that displacement of the growing shale supplies, the Opal hub remains relatively strong as the supplies have shifted more to serve the West Coast market," Kalan says.

Opal hub

Locals explain the town of Opal, Wyoming, received its name when the early-day settlement emerged as a cattle-loading hub on a railroad siding. Cowboys from area ranches herded cows into the chutes, loaded them on trains, then climbed back in their saddles and headed home with friendly waves to each other and a "See 'ya, ol' pal!" The place became known as "Ol' pal" and over the years that became Opal.

It is still very much a hub—nowadays for gas and NGLs rather than steers. The cattle pens disappeared long ago, replaced by pipelines and a truck/tank car loading rack to handle NGLs coming out of the Opal plant. It currently runs near its 1.45 Bcf per day nameplate capacity and processes around 65,000 bbl. per day of NGLs, Kalan says.

Opal has emerged as an important gas and NGL delivery point because of service from five interstate gas transmission lines: Colorado Interstate Gas Pipeline, Kern River Gas Transmission, Northwest Pipeline, Questar Overthrust Pipeline and Ruby Pipeline. Two NGL systems flow out, Overland Pass Pipeline, jointly owned by Williams and Oneok Partners LP and Enterprise Products Partner's Mid-America Pipeline System, adds Kalan.

The new Ruby Pipeline, which entered service in the summer of 2011, has been an important transmission link in getting Wyoming gas to market—and its adapting to that new westward marketing shift. The 42-inch, 680-mile line extends from Opal to Malin, Oregon, and complements Opal's West Coast links provided by Kern River, which entered service to California in the 1990s, and Williams' own Northwest Pipeline to the Pacific Northwest, which dates to the 1950s.

Growing Wyoming gas production has created demand for other midstream infrastructure to the hub. Gas storage, or the lack of it, has historically been an issue for producers and customers but that changed in the past year.

Peregrine Midstream Partners LLC opened its Ryckman Creek gas storage project outside Opal in August, then declared an open season in October for additional capacity to become available in April 2013.

"Ryckman Creek is the only gas storage facility serving all the pipelines at the Opal hub and offers an excellent location for gas storage due to the supply liquidity at the hub, as well as access to a diverse array of markets," Jeff Foutch, Peregrine's chief commercial officer, tells Midstream Business. "In addition, it will provide tailored gas storage services to meet the needs of a wide range of potential gas storage customers, including electric utilities, IPPs [independent power producers], LDCs [local distribution companies], gas producers and marketing entities doing business in the Rocky Mountain region and throughout the western U.S."

The new storage complex uses a partially depleted gas field 25 miles southwest of Opal in Uinta County, Wyoming, relying on six injection-withdrawal wells, two observation wells, two saltwater-disposal wells and 30,000 horsepower of compression. Combined meter capacity exceeds 1 Bcf per day. Initial working gas capacity is 18 Bcf for the upcoming 2012-2013 storage season, increasing to 35 Bcf by the first half of 2014. A planned Phase II will increase gas capacity to 50 Bcf, depending on market demand.

To the south along the Colorado-Wyoming state line lies the Sand Wash basin, another area prospective for the Niobrara. Quicksilver Resources Inc. and a unit of Royal Dutch Shell plc announced recently they will jointly develop Sand Wash acreage. The area is handy to midstream infrastructure operated by Williams and Summit Midstream Partners LP. Early drilling results indicate the Niobrara may be comparatively liquids rich in the area.

Ultimate frack jobs

Farther south, the Piceance basin covers a big piece of northwestern Colorado and has been home to conventional oil and gas production for decades. Major Piceance producers include WPX, spun off by Williams early this year, and Encana.

The Piceance provided the stage for one of the most exotic attempts ever to liberate natural gas from tight rock formations: The federal government's Operation Plowshare, launched in the 1960s and designed to find multiple, peaceful uses for atomic energy. Gas well fracturing was one idea that came to mind and the program detonated two low-yield, underground atomic bombs in 1969 near Parachute, Colorado, and in 1973 near Rifle, Colorado.

Both worked—and worked splendidly. However, the nuclear explosions left the abundant gas in place mildly radioactive and unsuitable for commercial use. A third Operation Plowshare test in New Mexico's San Juan basin left similar results.

Now, horizontal drilling and hydraulic fracturing—not as dramatic as atomic bombs but more practical—combine to open up the region's rich-gas plays with midstream players responding in kind.

Williams recently broke ground on a $190 million expansion of its gas processing plant at Parachute, Colorado. The new cryogenic unit will increase the plant's NGL production capacity to 30,000 bbl. per day from 6,000 bbl. per day. The company expects construction to be complete by third-quarter 2014. Parachute and three related facilities have a 1.4 Bcf per day capacity currently. To the north, Williams' Willow Creek plant, located east of Rangely, Colorado, can handle 450 MMcfd, producing as much as 30,000 bbl. per day of NGLs.

Mid-America Pipeline announced construction will start by year end on its new Western Expansion Project II, a 95-mile NGL pipeline that crosses the border from western Colorado into eastern Utah. Completion is expected in the middle of 2013. The project received necessary Bureau of Land Management approval in September for 60 miles of right-of-way across federally owned land.

The project will increase Mid-America's capacity to move NGLs from Wyoming and Colorado to Hobbs, New Mexico, and on to the Gulf Coast. The pipeline will increase current capacity by 15,000 bbl. per day.

A new player

Summit Midstream, a master limited partnership formed in 2009, is one of the newer players in the Piceance. It currently operates 275 miles of pipeline in western Colorado and serves some of the largest producers operating in the basin such as Encana, WPX, Antero and Bill Barrett Corp., Steve Newby, president and chief executive, tells Midstream Business. In September, Summit announced the acquisition of ETC Canyon Pipeline, LLC, which serves the Piceance and Utah's Uinta basin. The Canyon system includes 1,600 miles of pipeline and NGL processing capacity of 97 MMcf per day

The liquids-rich Mesaverde has been the conventional producing formation in the Piceance for years, but Newby points out the underlying Mancos and Niobrara shale formations are now emerging as significant resources.

"It is a significant resource in the Piceance," he says, adding the Niobrara tends to be more gas prone in the southeastern part of the basin. "But these are big wells. We're hearing producers talk about EURs [estimated ultimate recovery] of 6 to 8 Bcf per well with very high initial production rates. As you move farther west, there's a belief, and some early evidence, that the Mancos and Niobrara are more liquids rich," Newby says. As further proof, in a recent investor presentation, WPX estimated its Mancos-Niobrara acreage could add 20-30 trillion cubic feet equivalent in resource potential.

"That excites us," Newby understandably adds of the Mancos play's potential, "and Summit is well positioned to provide midstream solutions to support our customer's production efforts."

The ETC Canyon acquisition moves Summit into another basin that has had conventional production for many years—eastern Utah's Uinta, which has drawn increased interest recently from several exploration and production companies. One is Newfield Exploration, which told investors in a September presentation it plans a six- or seven-rig drilling program in the area following good results from wells targeting the oil-prone Uteland Butte formation, a member of the Green River formation. Two Uteland Butte horizontal wells had initial production rates of more than 1,400 bbl. of oil equivalent per day, composed of 87% oil.

Newby says the Uinta currently has 40,000 to 50,000 bbl. per day of crude oil production from the Wasatch formation. The waxy crude always has proved to be a challenge to producers, however, due to its high paraffin content. Pipelines can't handle it so production moves to Salt Lake City-area refineries in heated and insulated trucks. Growing truck traffic along curvy, two-lane U.S. 40 has the Utah Department of Transportation mulling options to widen the highway as production increases.

Both the Mancos and Niobrara lie below the Wasatch in the Uinta, "and I'll tell you there's not been much exploration of the Mancos and Niobrara in the Uinta that we've seen," Newby adds. "But the formations extend over there, there's no doubt about it. It's an area we like a lot from both a resource potential and a competitive situation, and we're focused on it."

Frank Nieto, editor of Midstream Monitor, contributed to this story.

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