Gas-Storage Strategies

The 20-inch-diameter lines in the piping room at Inergy LP’s Stagecoach facility near Owego, New York, move gas into and out of storage.

North America has about 4.5 trillion cubic feet (Tcf) of working gas-storage capacity today, but is that enough? Probably not. Recent development of new unconventional gas resources, estimated to be as high as 652 Tcf, will drive a need for more storage capacity.

In fact, consulting firm ICF International, of Fairfax, Virginia, predicts that some 371- to 598 billion cubic feet (Bcf) of storage capacity will be required by 2030. That build out, mostly of high-deliverability caverns with gas to fuel power generation, could cost between $2- and $5 billion

This price tag represents only 3% of the total $120 billion cost estimated for new midstream oil and gas infrastructure to be built during the next two decades (80% will be spent on new pipelines, 10% will fund gas processing, and the rest is earmarked for other services and equipment). Still, the requirement for new gas-storage capacity should not be taken lightly.

New storage would have a favorable impact on gas prices at the Opal Hub, says John Hopper, president of Peregrine Midstream Partners LLC.

In addition to providing a home for seasonal supply and a facility for arbitrage, storage acts as a gas-price equalizer, smoothing out periods of over- and under-production.

For example, Rocky Mountain gas producers, to some extent, are price takers, says John Hopper, president of Peregrine Midstream Partners LLC, Houston.

“They (Rocky Mountain gas producers) don’t have enough storage alternatives available in the area, although they do have more long-haul pipeline access now than in the past. But, even with that, the shale-gas dynamics in other parts of the country make storage even more vital,” he says.

New storage would have a favorable impact on gas prices at Wyoming’s Opal Hub, because the 3.5-Bcf-per-day gas-trading point is currently without an associated large storage presence, Hopper says.

“That general area just screams for storage. It would offer producers more flexibility to do something with their gas during the off-peak seasons. During peak demand, the local distribution centers (LDCs) and marketers like to have that high-deliverability storage. Such storage capacity will help dampen price volatility. Without it, producers are subject to the whims of the marketplace.”

Price volatility can also lead to demand destruction, because it prompts fuel-switching by power plants. The good news: As oil prices rise, power generators are less likely to switch from gas to fuel oil.

The bad news: About 50% of electric generation is fueled by coal. Coal-fueled power generators like the price stability and long-term contracts they get from the coal industry. Until coal plants are equally included in new carbon-emissions regulation, coal continues to be an attractive fuel source for power plants. And coal-plant operators are unlikely to be coaxed into retiring coal-fueled plants to build new cogen plants while gas prices remain volatile.

More bad news: In its Annual Energy Outlook 2010 report, the Energy Information Agency (EIA) documents a 1% drop in electric demand in 2008 and a 3% drop in 2009—the first time in 60 years that electric use fell two years consecutively. EIA analysts point to the slumping economy and improving energy efficiencies as the culprits. Energy intensity, measured in units of energy per unit of GDP, is forecast to fall by 1.9% per year through 2035.

As a result, gas producers and midstream operators are well-advised to combat price volatility whenever possible. Plentiful production and predictable gas prices could help offset the incremental loss of industrial-demand markets. Thankfully, today’s gas-storage owners, operators, builders and capital markets are up to the challenge. Which begs the next question: Where is the best place for new storage?

“The Marcellus is going to change the dynamics of the pipeline grid,” says Larry Bickle, above, non-executive chairman of Quantum Natural Gas Storage.

Location, Location

Project managers and investors use a variety of methods to determine the best salt-dome or depleted-reservoir site for storage.

Larry Bickle looks at a forest and sees the trees. Bickle is the non-executive chairman of Quantum Natural Gas Storage, a division of Quantum Energy Partners.

“Think of a pipeline grid as the roots, trunk and branches of a tree,” he says. “If the placement of a storage facility is at the tip of a root near oil and gas production, it is not useful because it is tied to only that supply. Moving up the tree where several big roots intersect, where supply comes from several sources, is a better site. It alleviates the potential of total disruption from one major event.”

Midway up the trunk of the supply chain is also not optimal, he warns. “Gas that is going by the front door of a storage facility can’t get in or out because, if the pipeline operators are doing a good job, the capacity of the transmission pipeline is already committed to someone else.”

Siting near a branch tip, or a particular market area, is also unsuitable. Should that market demand decline, there is no other sales option. “Backing up to a junction of several major limbs that lead off from each other allows access to multiple opportunities to reach profitable markets,” he says.

“One test factor we use to determine best storage placement is the availability of multiple sources that don’t have ‘common-mode failure,’ such as three supply lines from the Gulf of Mexico that are vulnerable to hurricanes, or four supply lines from the Midcontinent that can experience an ice-storm event.”

Since 1980, gas volumes in underground storage have steadily increased.

Also, builders should ensure that gas is not sent to markets that peak at the same time. “It is better to site a storage facility to feed into the Mid-Atlantic, New York and Chicago markets, because those markets do not have the same peaking cycles, so more service can be sold.”

Bickle says new capacity is needed near key areas of major supply growth. “The Marcellus is going to change the dynamics of the pipeline grid and California continues to be underserved,” he says.

“Interestingly enough, I think that places that are underserved are also the places that are going to have to change from coal- to gas-fired generation, like the ECAR (East Central Area Reliability) region. That area has mostly coal-fired electricity, but it will have to convert to gas-fired generation due to global-warming initiatives and carbon-sequestration regulations.”

ECAR includes Indiana, Ohio, Michigan, Pennsylvania, West Virginia and Kentucky.

A worker inspects a gas wellhead on the Stagecoach property in Tioga County, New York. Inergy acquired the facility in 2005 and has expanded and upgraded it continually.

Magnum Gas Storage

Yet, according to ICF, about half of all projected storage expenditures will target the Southwest or Southeast, where the majority of salt-cavern development is expected to occur.

Nonetheless, buried beneath the central Utah desert, a large natural salt formation is about to become the first fully integrated energy-storage facility to be developed in the West.

The project, the first step in a larger complex to be known as Western Energy Hub, was conceived by a Salt Lake City-based developer, Magnum Gas Storage LLC (owned by Magnum Development LLC), a Haddington Ventures LLC portfolio company. Houston-based Haddington is a private-equity provider focused on the midstream.

“The two separate grids for electricity and gas in the U.S. are quickly becoming a thing of the past,” says Rob Webster, managing director of Magnum Gas Storage LLC.

“We are building it here because of the strategic location and the fact that this is the only salt structure that has been discovered in the Rockies where a development of a large Gulf Coast-style cavern is feasible,” says managing director Rob Webster. Until now, most salt-cavern storage facilities were located in salt domes found along the coastlines of Louisiana, Mississippi and Texas.

When completed, the four-cavern, high-deliverability, multicycle storage facility will bring a total of 42 Bcf of working gas storage to the region. According to the design, gas will be stored in caverns 1,100 to 1,300 feet tall, 300 feet in diameter, located 3,000 feet below the ground in a naturally occurring salt formation. The caverns will be developed by solution mining, or leaching, which dissolves the salt deposit from the formation, creating brine that will be extracted to leave a large empty space. Salt caverns are designed for faster storage-cycling rates than traditional gas storage in aquifers or depleted reservoirs.

Initially, Magnum will develop two salt caverns at the 2,150-acre site in Millard County, north of Delta, Utah. Each will contain some 10.5 Bcf of working storage capacity. The facility will be capable of injecting up to 0.36 Bcf per day of gas and withdrawing up to 0.62 Bcf per day and will cycle inventory about four times per year. Magnum plans to start construction, pending approvals for state and federal permits, in mid-2010. The first cavern is expected to be available for service in 2013.

The storage facility will serve two primary purposes. It will meet producers’ and marketers’ high-deliverability storage requirements and help enable gas-fired power producers to provide load-following generation as a complement to the intermittent nature of alternative energy sources, says Webster.

According to recent data, wind power is the fastest-growing energy technology worldwide, expanding at an annual rate of more than 30%. The abundance of wind energy in the West makes it one of the nation’s largest renewable energy resources. Historically, western states have relied upon natural gas, coal and hydropower to meet their energy needs, but renewable energy is expected to play a much greater role in the future.

Yet, like many renewable resources, wind energy has a weakness—it is intermittent. The high-deliverability of the Magnum facility will backstop power generated from wind, solar and other renewable resources when they are not available.

While all types of infrastructure are needed to support this growth, the West is especially low on gas-storage capacity. According to the EIA, gas-storage capacity in the West is about 660 Bcf, compared to 2.2 Tcf in the East.

The Magnum facility will be built near the center of the western gas-transmission and electric power grids. The project is the first phase of Magnum’s plan to support a hub serving as a crossroads for existing and developing electric, gas and other energy infrastructure. Second-phase plans tentatively include developing sites for a combined-cycle power plant or creating more caverns to house compressed-air energy storage.

“The two separate grids for electricity and gas in the U.S. are quickly becoming a thing of the past,” says Webster. “The two are becoming integrated into one national energy grid.

Computers monitor every aspect of storage, injection and withdrawal at the Stagecoach facility, which can hold 26 billion cubic feet.

“This project will make the energy grid more efficient, reliable and cost effective by providing seasonal storage and short-term cycling and balancing services. Everything we do in connection with this project is designed to address renewable energy’s most critical issue—its intermittent nature.”

The facility will also support lower carbon emissions produced by coal plants and more efficient pipeline operations, says Webster. As a sort of “energy hierarchy,” the transmission of wind energy generally takes priority when it is being produced. To accommodate wind-fueled power generation, gas- and coal-fired power plants have to slow down their production levels. When this happens, carbon emissions increase at coal-fired plants because they are not operating at optimum levels and gas backs up in pipelines, creating a strain on infrastructure.

This scenario creates a difficult balancing situation for gas dispatchers, says Webster. “The problem will only get worse as more renewables come on line and are integrated into the electric grid. We believe high-deliverability gas storage that can be called on quickly when the wind isn’t blowing is an important solution.”

It seems the markets agree. Thus far, the Magnum project has received a positive response from the market, evidenced by its open season ending July 31, 2009, which received responses from 26 bidders requesting more than four times the storage capacity offered.

According to the plan, Magnum’s facility will have direct or indirect interconnects with multiple pipelines originating out of the Rockies. The project includes a 61.5-mile, 36-inch header pipeline extending to points of interconnection with Kern River Gas Transmission Co. and Questar Pipeline Co. near Goshen, Utah. It will serve the Opal Hub’s pipeline connections through backhaul and displacement.

Webster and others hope the new facility will help mitigate some of the price volatility at Opal, the largest gas hub in the U.S. The annual volatility at Opal, from 2005 to 2008, ranged from 99% to 629%. Comparatively, the volatility at Henry Hub during the same period was 51% to 92%.

“Opal is a major, growing gas hub through which gas is supplied to the Midwest and western states,” Webster says. “But it is a major market hub that we think is greatly in need of gas storage.”

Inergy constructed its Stagecoach facility to blend into the pastoral countryside, making it an environmentally unobtrusive neighbor for the nearby communities.

Ryckman Creek

A second project planned near the Opal Hub in Uinta County, Wyoming, is the Ryckman Creek Gas Storage project. It is being developed by Ryckman Creek Resources LLC, a wholly owned subsidiary of Peregrine Midstream Partners, formed in January 2009 by the founding management of Falcon Gas Storage Co., Houston.

The $250-million project will involve converting an existing and partially depleted oil and gas field into a high-deliverability, multicycle storage facility that will also produce oil and gas liquids.

“The initial design will include 28.5 Bcf of working gas capacity with an average two to three cycles per year,” says John Hopper, co-founder and managing director.

“Our Phase 1 design is for up to 265 million cubic feet per day of injection and 360 million cubic feet of withdrawal per day. We can expand working gas capacity to 50 to 60 Bcf, injections to more than 500 million cubic feet per day, and withdrawal to 1 Bcf per day, by drilling more wells and adding more compression if the market indicates more cycles are needed. We will pancake-stack our services, so we will have four-turn service down to one-turn service,” he says.

The project will meet demand for firm, peak-day, load-following, balancing and seasonal storage services from gas markets throughout the Midwest, Rocky Mountains and western U.S., he says. Ryckman Creek Resources has filed for FERC approval to charge market-based rates for the services it will offer.

The company plans to hold a nonbinding open season to gauge customer interest during the latter half of 2010. If all goes according to plan, construction will begin in the spring of 2011. The developers are shooting for a projected in-service date of April 1, 2012.

“We see the need in the Rockies for more gas-fired generation to backstop wind power.” says Hopper. “The more gas-fired generation you have, the higher the need for high-cycle gas storage to meet the load-following and hourly-balancing requirements of gas-fired turbines. We saw that in spades in Falcon’s North Texas facilities where there was a lot of gas-fired electric generation, and we see a similar trend here in the Rockies. In fact, if you are standing on the Ryckman Creek plant site, you can see a wind farm on the next hilltop over. It’s right there on top of us.”

The depleted reservoir at Ryckman Creek was one of the first fields in the old Overthrust trend developed by Amoco, Chevron, BP and others in the late 1970s and early 1980s, he says.

“It was one of the larger Overthrust fields that precipitated quite a bit of exploration activity in southwestern Wyoming and northeastern Utah. This location is in the sweet spot of that trend and it still has oil and gas in it. We will separate out the oil at the wellhead and get the liquids out with a gas-processing plant during the cycling that occurs as part of storage operations. We pioneered this process with our North Texas facilities we developed at Falcon,” says Hopper.

Hopper and his team, including co-founders Jeff Foutch, Keith Chandler, and Tom Wynne, chose this location for a storage facility because they felt the need for gas storage in the Rockies stood out among all the other areas they studied.

“We sifted through a lot of storage-conversion opportunities and came up with Ryckman Creek as our No. 1 choice,” says Hopper. “It’s a great reservoir in a fantastic location and we were able to effectuate a transaction with Nielson Energy Group LLC, which owned the field at that time. We also liked this location because we’re able to keep the capital cost down by availing ourselves of some of the existing infrastructure in the area.”

Based on the feedback the team has had so far, demand for the facilities is “very robust.”

To move the gas, Ryckman Creek will have contractual connections to four pipelines at its 22,000-horsepower compressor station at Canyon Creek, purchased from Kinder Morgan.

“It’s about four pipeline-miles west of the Ryckman Creek site,” says Hopper. “We will make bilateral interconnects to the Kern River, Questar and Overthrust pipelines there.” The company will retrofit the compression it owns at Canyon Creek to accommodate high-pressure injections and withdrawals from Ryckman Creek. At some point, the facility could be expanded with another 22,000-horsepower compression for more high-turn services.

The Overthrust Pipeline is actually two pipelines in one, Hopper explains. It includes capacity for both the Overthrust line (operated by Questar) and the Trailblazer/Rockies Express pipelines (operated by Kinder Morgan), which have leased capacity within the Overthrust Pipeline.
“This arrangement gives our shippers the ability to nominate to receive their gas at our receipt-and-delivery point at Canyon Creek, which will be part of Ryckman Creek. All of these pipes at Canyon Creek tie directly into the Opal Hub.”

Down the road, Ryckman Creek will tie into the Ruby and Northwest pipelines. The management team has initiated the four- to six-month pre-filing process with FERC and will file for the FERC 7(-c) certificate this fall to be ready to break ground in the spring of 2011. Hopper expects to be up and running about a year after that.

“This is our headliner project,” says Hopper. “We’ve got two other projects that we are working on, although, for competitive intelligence reasons, I can’t tell you where they are. But we think more gas storage is needed in other parts of the country, too.”

Hopper says the facility will do more than simply store gas. “At Falcon, we branched out into gas processing and liquids production. At Ryckman Creek, we will have those elements associated with that project also. It’s a nice way to enhance the profitability of our gas-storage project.”

He expects the facility to produce oil and strip gas liquids out of the gas stream. The company will build a nitrogen-rejection and cryogenic gas-processing plant and amine and dehydration facilities to remove CO2 and other inert gases and water.

“The gas-liquids production was a good part of our business at Falcon and we expect it will be with this project as well,” says Hopper. “In fact, at most of the projects we look at, we like the hydrocarbon-recovery feature if we can find the right reservoir at the right place with the right characteristics, with high-deliverability storage and enhanced hydrocarbon recovery. We like that business model. It’s worked well for us.”

NorTex Gas Storage

A storage A&D deal took place in North Texas this year. Private-equity firm Alinda Capital Partners, with $7 billion under management, acquired NorTex Gas Storage for $505 million, including the repayment of all third-party debt. (Arcapital Bank BSC owned Falcon Gas Storage, which owned NorTex Gas Storage. The latter owned Hill-Lake and Worsham-Steed working gas-storage facilities.) The deal was effective April 1, 2010.

Inergy’s newly constructed Thomas Corners storage facility in Steuben County adds 7 billion cubic feet of capacity in western New York.

“Nothing has changed regarding the quality of storage services we offer in North Texas,” says John Holcomb, vice president of marketing for NorTex.

“We’ve seen a continued high demand for storage services,” says John Holcomb, vice president of marketing for NorTex Gas Storage LP.

“We still have excellent customers, lease firm-storage capacity and provide other services, particularly those related to the gas-fired power-generation market. Along with normal interruptible services, we also do summer power-plant hourly profiling, park and loan and winter peaking services.”

NorTex continues to own and operate the two gas-storage facilities, which have an aggregated 35 Bcf of capacity. They primarily serve the Dallas-Fort Worth area and gas production in the Barnett shale play.

Hill-Lake, in Eastland County, Texas, was operated as a producing oil field until the mid-1960s. The 12-Bcf-capacity storage facility serves customers from Dallas to the Carthage energy corridor with a maximum withdrawal and injection of 400 million cubic feet per day.

The facility has access to bi-directional receipt and delivery points via the Atmos Line X and North Texas Pipeline—jointly owned by Energy Transfer Partners and Enterprise Products. The complex includes a gas-processing facility with 60 million cubic feet per day of capacity.

Worsham-Steed Storage, also a depleted oil and gas reservoir, serves the greater Dallas/Fort Worth metroplex. It has 23 Bcf of working gas-storage capacity and 450 million cubic feet of withdrawal and injection.

The complex includes the 60-mile Worsham-Steed Pipeline, which moves gas from Jack County, Texas, to interconnections with the North Texas Pipeline, Atmos Line X and Energy Transfer’s Cleburne Extension. The Worsham-Steed plant can process up to 60 million cubic feet per day.

Holcomb agrees that storage is an important factor to remove volatility from gas prices.

“In today’s market, we’ve seen a continued high demand for storage services, especially during the significant drilling activity of 2006 to 2008. We are in the middle of the Barnett shale, the first shale play to be successfully developed. While drilling has slowed somewhat, we are still seeing high demand for storage,” he says. No major expansions are planned by the company this year, but it could add compression and other fine-tuning at its operations.

Inergy LP

While there is much interest in storage caverns and their accompanying facilities in the Rocky Mountains and Texas, one of the most vital gas-storage regions is in the Northeast.

Inergy LP, a gas-storage company with most of its assets in New York, has been growing by leaps and bounds over the past several years. In April, it gained 7 Bcf of new storage when its Thomas Corners storage facility came online.

"Similar to the real estate business, storage is all about location,” says Bill Moler, senior vice president of Inergy LP.

“We now own and operate 40 Bcf of gas storage in upstate New York,” says Bill Moler, senior vice president. “Stagecoach has 26 Bcf and we have another 6.2 Bcf at Steuben.”

Headquartered in Kansas City, Missouri, the company also operates businesses that include liquid petroleum gas storage, solution-mining and salt production, retail propane, transportation, and wholesale marketing.

Inergy acquired its Stagecoach facility in 2005 and has continually expanded and upgraded the operation. “It is unlike any gas-storage facility you’ll see anywhere,” says Moler. “We have deliberately sought to install leading-edge technology. For example, all of the 37,000 horsepower of injection compression has serial numbers in the single digits. These electric-driven magnetic-bearing compressors are flexible and efficient. The latest installation, a 12,000-horsepower centrifugal gas unit, is the first of its kind from Dresser-Rand Co. and is cooled with high-thermal-efficiency hydrogen instead of recycled gas.”

These high-tech innovations increase efficiency. For example, a typical gas compressor’s bearing will have lube oil in it, Moler explains. The lube oil can become entrained in the gas stream and, if not filtered out during the storage application, can get injected downhole.

“If that gets into the reservoir, over time it will gum up and require workovers and acid jobs to keep the reservoir efficient. At this location, the only lube oil we have on site is in our pickup trucks.”

Rows of gas meters attest to the capacity of Inergy’s Thomas Corners facility in New York.

The facility itself is aesthetically pleasing. It is lined with Pennsylvania blue stone and built into a hillside, so viewers from the street would not realize a gas-compressor facility exists nearby.

As for having its storage facilities situated in the Northeast, “We are very lucky,” he says.

“Similar to the real estate business, storage is all about location. We have all this storage capacity sitting right outside the largest demand center in the world.”

The Northeast market, historically short of storage capacity, always has winter-summer seasonal demand, “despite the basis being fairly flat right now without a lot of volatility,” he says. Yet, he expects industrial load to regain its former levels. For now, Inergy has 100% of its available capacity in every asset sold out under long-term contracts.

The company’s strength lies in its pallet of storage services, ranging from high-deliverability multicycle service at Stagecoach to single-cycle seasonal service, and everything in between.

A dehydration pad for storage wells coexists with wildflowers on the grounds of the Thomas Corners facility.

“We have this flexibility because of the way the wells were drilled into the rock. Steuben was drilled with vertical wells many years ago and doesn’t enjoy the new technology that is available today, so it is a single-cycle service. Thomas Corners was drilled with large-bore high-angle wells, so it’s providing a two-cycle service. Stagecoach was drilled with very large-bore, long-lateral horizontal wells, which allow very high-deliverability service.”

Because of the subscribed capacity of its current assets, Inergy continues to seek growth through acquisitions and expansions. This past January, the storage-provider signed a definitive agreement to acquire the Seneca Lake gas-storage asset in Schuyler County, New York. When the sale is approved, Inergy LP’s wholly owned subsidiary, Inergy Midstream, will purchase it and two related pipelines for about $65 million, from Iberdrola/New York State Electric and Gas. The sale is expected to close near year-end.

Seneca Lake is a salt cavern with fast turnaround peaking service. The facility has a maximum withdrawal capability of 145 million cubic feet per day and maximum injection capability of 75 million per day. It is connected to the Dominion Transmission System via the 16-inch, 20-mile Seneca West Pipeline and, indirectly, to the city gate of Binghamton, New York, via the 12-inch, 37.5-mile Seneca East Pipeline, which runs within about three miles of Inergy’s Stagecoach North Lateral interconnect with the Millennium Pipeline.

The 2-Bcf underground salt-cavern storage facility is on Inergy’s U.S. Salt LLC property outside Watkins Glen, New York. The historical salt-refining facility has been in operation since the late 1800s.

“We bought that salt-refining company in 2008 for two reasons,” says Moler. “First, it gives us a way to dispose of brine in the Northeast, which can be a significant technical impediment to developing salt-cavern storage. Second, we picked it up so we could have available pre-solution-mined cavern space to store natural gas, propane and butane. That’s what we call the gift that keeps on giving, because as we solution mine to make more salt, we pick up about 1 Bcf of storage space per year.”

Inergy also owns and operates the 1.7-million-barrel-capacity liquefied petroleum gas (LPG) Finger Lakes storage facility in Bath and is developing a 4-million-barrel LPG facility in Watkins Glen. Most of the butane at Finger Lakes comes from oil refineries near Philadelphia, while the Watkins Glen facility will store a mix of refinery butanes and indigenous Marcellus processed propane. Inergy is the fourth-largest U.S. propane distributor, a business that contributes 60% of the company’s revenue.

Yet, there is more to come. The company has two new pipeline projects on the table. Its North-South project will bring gas through its Stagecoach storage via firm transportation between the Tennessee Gas Pipeline and the Millennium Pipeline. It is also building a 42-mile pipeline to interconnect with the Transco Pipeline in Sullivan County, Pennsylvania, in 2012. It will allow Marcellus shale-gas producers to bring gas into Stagecoach via the Marc-1 pipeline and from Stagecoach back out into Tennessee, Transco or Millennium pipelines to reach several other markets.

“Producers and shippers will be able to poll those markets on a daily basis for optimal prices, or if there is an outage downstream, they have an alternative to move their gas,” says Moler. “The redundancy ensures reliable service to the local distribution centers and market access to the Marcellus producers.”

Inergy has a robust pipeline of new opportunities to evaluate, says Moler. “If we see other opportunities to build out or acquire additional assets, we are certainly open to that. We are always on the hunt.”