Energy investors began 2011 with relieved optimism as markets indicated a turn-around in the U.S. economy and the wealth of new oil and gas plays provided by horizontal drilling and fracking technologies.

Analysts, such as Bob Doll with BlackRock Inc., an investment-management company, expressed confidence that the year would provide double-digit gains from the American stock market. Elsewhere, Barclays Capital expected a 22% return on European shares.

Instead, the stock markets experienced unforeseen roller-coaster volatility around basically flat earnings, and the European investors “have suffered double-digit losses,” according The Economist. Joked one industry insider, “Government bonds have turned from offering a risk-free return into becoming a return-free risk.”

Yet, thanks to the ingenuity of America’s oil and gas professionals, the domestic energy sector continues to perform. Upstream producers continue to find and develop prolific oil and natural gas liquid plays, despite the slight decrease in enthusiasm for dry-gas plays. And the oil and gas fields in the Rocky Mountains are on the top-ten list of regions with rich returns for upstream and midstream operators.

One billion barrels

The most recent example of investment dollars turning into Rockies black gold comes from Anadarko Petroleum Corp, which recently revealed early drilling results in its Weld County, Colorado field. If the field proves up, the play will keep midstream operators busy moving that production to market for years to come.

Anadarko reports that early drilling results indicate that the company could produce the equivalent of more than 1 billion barrels of oil from the Weld County energy field, and it plans to eventually drill 1,200 to 2,700 wells in the area.

The company reports that 11 horizontal wells drilled in Weld’s Wattenberg field yielded “strong” initial rates of production and high levels of liquids, which have commanded better prices than natural gas. The Houston-based company said its program of horizontal drilling in the Wattenberg field is among its best on U.S. land and should quickly generate “significant” cash flows. In fact, the region could produce the equivalent of 500 million to 1.5 billion barrels in oil, natural gas liquids and natural gas, Anadarko said.

“Based upon the early results of Anadarko’s program in the Wattenberg field, we are confident the liquids-rich horizontal Niobrara and Codell opportunity provides a net resource potential of 500 million to 1.5 billion barrels of oil equivalent, and it’s located right in the heart of our existing core areas,” said Anadarko’s senior vice president of worldwide operations, Chuck Meloy, in a public statement.

“Our activity, which has primarily targeted the Niobrara formation within the Wattenberg field boundaries, has achieved high liquids yields and excellent well performance with average initial production rates of about 800 barrels of oil equivalent per day,” he said.

Anadarko plans to drill 160 horizontal wells in the area in 2012, up from previous plans for 40 wells, and could eventually put 1,200 to 2,700 wells there.

“The results to date demonstrate the Wattenberg horizontal program is among the most cost-efficient development projects in our U.S. onshore portfolio, and with initial wells averaging payouts of 10 months, we expect it to quickly become a self-funding, significant cash flow generator,” he said.

The discovery’s significance compelled the Colorado’s governor, John Hickenlooper, to say, “Anadarko’s announcement today shows once again that Colorado is a leader in the energy sector of our country’s economy. We are thrilled to see the company plan a significant investment in Colorado. This expected growth will create jobs and make more revenues available to local communities. We look forward to supporting Anadarko, its workforce of 1,000 people already here and the thousands of contractors it hires throughout the state.”

Anadarko holds interests in more than 350,000 acres in the Wattenberg field and operates more than 5,200 wells. And where upstream goes, midstream follows.

First independent storage

Recently, upstream producers welcomed the first operational independent natural gas storage facility to begin operations in the Rocky Mountain region. East Cheyenne Gas Storage LLC, a natural gas storage project developed by Merchant Energy Holdings LLC in Northeast Colorado’s Logan County, received FERC approval to put the facilities into service—which it did on December 6, 2011.

Merchant Energy continues to develop the East Cheyenne facility, which is sited on mineral leases held by Merchant in two nearly depleted oil and gas reservoirs known as West Peetz and Lewis Creek. The West Peetz storage area has a total working gas inventory of 11.5 billion cubic feet (Bcf), and the Lewis Creek storage area has a total working gas inventory of 7.4 Bcf.

In total, the facility will have a maximum injection capability of 350 million cubic feet (MMcf) per day and a maximum withdrawal capability of 350 MMcf per day at full build-out.

The project was conceived to meet the existing peak day and load growth needs in the Midwest and western U.S. In addition to serving customers in Colorado’s Front Range and shippers moving gas to markets off Natural Gas Pipeline Co.’s and Northern Natural Gas Company’s systems, the facility will provide storage and hub service options to shippers using the Cheyenne Hub.

“I don’t have the exact numbers, but about 22% of domestic production comes out of the Rockies area, and it only has about 9% of the storage capacity of the U.S. So I think there is an opportunity and a need to put more storage in place, not only to handle the vagaries of the gas market but also to support the loads of alternative energies that are developing.” — Andy Lang, founding partner of Merchant Energy Holdings LLC, management team leader and president of East Cheyenne Gas Storage

Independent system

“It’s independent, which means it is not an integral part of a pipeline operation,” explains Andy Lang, founding partner of Merchant Energy Holdings LLC, management team leader and president of East Cheyenne Gas Storage. Prior to Merchant Energy, Lang was president of Somerset Gas Transmission Co., chief executive of NiSource Inc.‘s subsidiary, TPC Corp., president and chief executive of Vastar Gas Marketing Inc. and director of transportation for Tennessee Gas Pipeline.

“In the Rockies, the existing storage facilities are all parts of pipeline systems, so they can’t be generally available for all comers. They are for very specific use,” he says.

Conversely, the East Cheyenne facility allows flexibility for producers that can use it to manage supply, pipeline operators that can use it to provide balancing services, traders and marketers that can use it to optimize seasonal spreads and intra-month volatility, and power generators that can use it to backstop load volatility.

The latter is important because much new gas-fired generation capacity is under development in the area to support compliance with Colorado’s Clean Air and Clean Jobs Act passed in 2010.

“The legislation provides for the retirement of a number of coal-fired electric generation plants,” says Lang. “Those retro-fits or combined cycle peaking facilities are in the process of being built. Much of that will be coming onstream in 2014 and 2015. It’s a significant amount of megawatts that will be converted to use gas.”

As currently designed, the project will have 16 well pads for gas injection and withdrawal, production and water injection and three water disposal wells. A compressor station and gas-processing facility will be developed on 60 acres. Gathering lines (6-inch to 16 inch pipe) will connect each well pad to the compressor station and associated facilities.

Initially, the project will have a 16-inch interconnect to Trailblazer pipeline, with the possibility of an additional 24-inch interconnect to the Rockies Express (REX) interstate gas pipeline and Kinder Morgan Interstate Gas Transmission LLC. A meter station will be installed at the REX-Trailblazer interconnects with the East Cheyenne pipelines. Merchant Energy is also developing the Tallulah Gas Storage project that will be built on the South Tallulah salt-dome formation in Madison Parish, Louisiana.

“We’ll put East Cheyenne is service in 2012,” says Lang. “It’s going to take about four years to completely build out the first phase of it. That’s a normal time frame on depleted reservoirs. We will re-inject base gas into the reservoir. And we have to push out any water that has migrated into the reservoir to create the space to store gas.”

By second-quarter 2012, the initial phase of the facility will have about 2 Bcf of working gas capacity, and about 8 Bcf by yearend 2013, 10 by 2014 and 13 by 2015 in West Peetz. Additional capacity development can be accelerated through further development of the Lewis Creek field and additional reservoir sands available for storage development.

The Rockies view

Also, despite the much discussed shale plays in the northeast and rich-gas plays in Texas, the Rockies continues to garner the attention of producers, contractors and capital providers with its own profitable production areas.

“There is a new shale play in the Rockies. It’s more liquids-centric play, called the Niobrara. It is expected to have very substantial potential and it’s found in North Central Colorado and into Wyoming,” says Lang. “It’s still in its infancy, but analysts are saying its potential is comparable, in size and prospectivity, to the Eagle Ford play in Texas.”

The real issue, says Lang, is that technology has allowed the current “shale explosion” to be expansive across many areas of the country. “There are new shale plays that people are talking about that haven’t even been prospected yet.”

Given the emergence of these areas, the potential for the midstream is “probably as great as it has ever been,” he says. Yet, due to the excess of natural gas supply, producers are heavily turning toward liquid plays. “Crude is selling about five times the energy value of natural gas. So energy companies preferentially want to find oil and associated liquids wherever they can.”

And midstream companies have stepped in to move the liquids and rich-gas production to processing facilities and to market. So far, the Rockies region is significantly built out with new and legacy assets. Yet, going forward, more infrastructure is needed.

But, are pipeline operators leery of building another Rockies Express, which was built as take-away from the Rocky Mountains to a terminus in Ohio—only to immediately find itself competing with Marcellus shale gas?

“The Ruby Pipeline was built to take gas out of the Rockies and into the California market. I think it will continue to play that role. Based on the information I have seen and heard, it is running very well. The high-load factor, in large part, is displacing Canadian supply,” says Lang.

“The Rockies Express was a different animal. It was built as a bullet pipe to carry gas from Evanston and Cheyenne all the way to Clarington, Ohio. With the advent of the Marcellus, and now the Utica, there is a lot of gas in that part of the world.”

High-price Rockies gas

More noteworthy, he says, is that the highest price gas is often trading in the Rockies at Opal. “So in the case of the Rockies Express, those dynamics have changed,” he says. “Yet, will gas flow from the Marcellus all the way to Evanston? I don’t think so. But it might mean that Rockies gas doesn’t make it all the way to Ohio. It might stop in the Chicago market, or down south in the Gulf Coast market via other pipes.”

That situation has caused the REX operators to think about storage, says Lang. As a bullet pipe heading to Clarington, the pipeline had no need for storage. But now, if the geology is amenable and within reasonable proximity, some storage opportunities might exist along the route.

“The dynamics of Rockies gas, overall, has changed. This producing region, that was pipeline-capacity constrained, has seen that constraint be significantly relieved with the advent of REX, Bison, Ruby and other pipes. As a result of that, we see more options, and that is where storage comes into play. If you’ve got storage, you can park your gas and pick the high-value market.”

Overall, the Rocky Mountains has historically proven to be a “very favorable province for oil and gas exploration and midstream development,” says Lang. “I don’t think there is anything that is changing that.”

While he admits that much of the region has been deemed an environmentally sensitive area, the producers and explorationists are operating within responsible boundaries.

“Personally, I think that is very manageable. With the Niobrara, the Pinedale Anticline, Piceance Basin, the Overthrust and such, and a number of other successful plays in the Rockies, we’ve seen a number of plays with great potential. The infrastructure is in place, or is being quickly added to follow the growth of those.”

For now, after the recent completion of the Ruby pipeline, the industry will experience a slowdown of major pipeline investment in the region. But on the liquids side, a significant amount of planned work and investment opportunities exist.

“And the Rockies are light on storage,” says Lang. “I don’t have the exact numbers, but about 22% of domestic production comes out of the Rockies area, and it only has about 9% of the storage capacity of the U.S. So I think there is an opportunity and a need to put more storage in place, not only to handle the vagaries of the gas market but also to support the loads of alternative energies that are developing.”

Logan County, the site of the Cheyenne gas storage facility, is also home to the Peetz Table Wind Energy Center. The 400-megawatt wind-generation plant is the second largest such facility in the country. “The alternative power-generation folks need the ability to respond to changes in the wind,” he says, “and gas storage provides that ability.”

Pipeline take-away

As mentioned, a lull in major take-away pipelines construction is expected due to the completion of the massive Ruby Pipeline, which removed a significant amount of capacity constraint.

Despite 2010 and 2011 construction delays from an unusually snowy winter and rainy spring in the west, and detours due to a protected western sage grouse habitat, El Paso Corp.'s Ruby pipeline was completed and began delivering gas in July 2011.

Ruby is a 680-mile, 42-inch gas transmission pipeline that begins at the Opal Hub in southwestern Wyoming and terminates near Malin, Oregon. It has an initial design capacity of up to 1.5 Bcf per day. The project has four compressor stations—one near the Opal Hub; one south of Curlew Junction, Utah; one at the mid-point of the project, north of Elko, Nevada; and one in northwestern Nevada.

Ruby offers Rockies producers a direct route to the West's premium market, Pacific Gas & Electric City gate in Northern California, and is predicted to provide one of the most low-cost routes out of the Rockies.

At the recent Colorado Oil and Gas Association's annual conference in Denver, Energy Epicenter, Matt Marshall, senior energy analyst at Bentek Energy, addressed lower rates from Ruby flowing west out of the Rockies. "The net price spreads slightly favor Canadian supply at Malin and Rockies suppliers need to reduce their prices about 10 cents from current levels," he said.

Also, a fire on December 10, 2011, damaged some midstream assets in Cache County Utah, halting flows through Ruby and sending prices lower. At the time, trading was halted at the Ruby Malin, Oregon hub. As a workaround, some 400 MMcf per day of gas was diverted to the Rockies Express pipeline, for delivery to Chicago and Ohio, and another 200 MMcf per day went through Kern Transmission for delivery to South California. Some 200 MMcf per day went into storage.

“Given excess take-off capacity of 9.3 Bcf per day, and 6.4 Bcf per day of Rockies flows after accounting for regional demand, we do not anticipate any major impacts to regional production, “ said David Tamerson, analyst for Wells Fargo Securities. “We could see some pricing pressure on Rockies producers if downtime is drawn out, as Opal spot process fell $0.15 relative to other hubs following the news.”

Demand-market deliveries

For the Uinta Basin, John Davis of Williams Northwest Pipeline said that the planned Opal Market Link, the 180-mile, 24- and 30–inch pipeline system will provide significant take-away capacity for natural gas liquids and unprocessed natural gas.

The proposed Opal Market Link will include construction of up to 145 miles of 24-inch diameter pipeline originating near Vernal, Utah, and extending north to the Opal Hub. Williams Northwest is also offering gathering service in the Uinta Basin to interconnect with the Opal Market Link project, as well as gas processing services at the Opal plant.

The initial design capacity of the Opal Market Link is planned to be about 400,000 dekatherms per day, which can be easily increased through compression or larger diameter pipe.

According to Davis, "Uinta Basin gas production has significant growth potential and the project will provide producers with low-cost transportation service and access to a vast array of natural gas and natural gas liquids markets." The project is expected to be completed in third-quarter 2015.

Williams Northwest is also planning the Jordan Cove-Pacific Connector to provide gas to a planned liquefied natural (LNG) gas import and regasification terminal in Coos Bay, Oregon. The Jordan Cove facility will be capable of receiving LNG supplies (primarily from Asia and Africa) from specially-designed marine vessels, storing the natural gas in liquid form and re-delivering the natural gas through interconnecting pipelines to the Pacific Northwest and adjacent markets.

The Pacific Connector Gas Pipeline project is a proposed 234-mile, 36-inch diameter pipeline designed to transport up to 1 Bcf of natural gas per day from the Jordan Cove LNG terminal to markets in the region. The Pacific Connector project includes interconnects to Williams' Northwest Pipeline near Myrtle Creek, Oregon; Avista Corp.’s distribution system near Shady Cove, Oregon; Pacific Gas and Electric Co.'s gas transmission system; Tuscarora Gas Transmission´s system and Gas Transmission Northwest's system, all near Malin, Oregon.

John Eagleton of Kinder Morgan discussed the Pony Express Pipeline's gas-to-oil pipeline conversion for a portion of the system from Freeman, Missouri, to Guernsey, Wyoming.

"There's more oil from the Bakken and Niobrara than there is gas, and we have the gas capacity,” he said. “We're converting a run to Cushing, Oklahoma, for oil processing and this could be completed in 2014."

The Pony Express Pipeline extends from gathering systems in the Wind River Basin of central Wyoming through Colorado, Nebraska and Kansas to the Freeman Hub, south of Kansas City. It has access to more than 6 trillion cubic feet of Rocky Mountain gas reserves.

According to Todd Kremer of Kern River Gas Transmission Co., the Apex Expansion Project will increase natural gas transported on the Kern River system by about 266 million cubic feet per day. When the Apex expansion is completed in November 2011, the Kern River system will be able to transport more than 2.14 Bcf of natural gas per day.

Kern River plans to install about 28 miles of new 36-inch diameter pipeline through the Wasatch Mountains in northern Utah, add 78,000 incremental horsepower of compression at one new compressor station and three existing compressor stations, and replace a compressor unit at one existing station.

By second-quarter 2012, the initial phase of East Cheyenne Gas Storage LLC will have about 2 Bcf of working gas capacity, and about 8 Bcf by yearend 2013, 10 by 2014 and 13 by 2015 in West Peetz. Additional capacity development can be accelerated through further development of the Lewis Creek field and additional reservoir sands available for storage development.

Shelley Wright of Questar Pipeline described the Overthrust Pipeline as a 255–mile, mostly 36-inch diameter pipeline located in southwestern Wyoming. The Overthrust is capable of a total daily capacity of 2 Bcf per day for Wyoming's Overthrust, Green River and Wamsutter producers. The Overthrust has interconnects to several major pipeline systems including Ruby, Rockies Express pipeline, Kern River and Wyoming Interstate Co.

Questar is working on a Uinta Basin transportation project that could deliver 110,000 dekatherms per day. Questar is also reconfiguring compression facilities and piping modifications at its Fidlar Compressor Station in Utah and hopes to deliver up to 25,000 dekatherms per day of additional capacity to the White River Hub from receipt points at Fidlar, Utah, or upstream of Fidlar.

According to Skip York of Wood Mackenzie Consulting, lighter crude from the Rockies is creating a glut at refineries in Cushing, Oklahoma, which are currently geared towards refining heavier and cheaper crude from the Gulf Coast. One of the current activities to alleviate the glut is that Bakken crude is shipped via railcar to a Tesoro Corp. refinery in Anacortes, Washington.

Tesoro currently takes delivery of about 1,000 to 2,000 barrels per day of Bakken crude which will eventually be sent to a West Coast refinery. Oil traders and shipping companies are building rail terminals in North Dakota and other northern or Midcontinent locations in a race to move crude south due to a dearth of pipelines to do the job.

"Pipeline tariffs remain cheaper than rail, but the boom period for crude-by-rail could last until at least 2013, when new pipelines between the Midwest and Gulf Coast regions enter into play,” sad York. "I believe that the imbalance will ultimately be resolved by the oil market. I don't see the situation quickly changing, but the level of discount will decrease as infrastructure improves.”