Combined Cycle

Gas storage increasingly linked to electric power plants’ needs


By Ann de Rouffignac
OGJ Online

HOUSTON, Mar. 19, 2001—Natural gas storage, for years largely the domain of gas distribution companies, is increasingly linked to the needs of electric power plants in today’s volatile gas market.

With a building boom under way in gas-fired electric power plants, industry experts say gas-fired generation is changing the way storage is used. Most new gas-fired generation lacks the capability to switch to fuel oil when gas gets scarce and expensive. Experts expect storage to serve as a price hedge and speed up physical deliverability.

“Electric generation is a huge new client for gas now,” says John Thrash, CEO of Houston-based eCORP Holding LLC. “Rather than fuel switch, power plants will start getting gas out of storage.”

The Federal Energy Regulatory Commission granted an affiliate of the company a permit in February for its new Stagecoach storage field, a 12 bcf storage project near Oswego, NY. It was only new storage facility in the cue at FERC.

Storage is becoming more important to power plant owners in today’s volatile gas market, says Jeffrey Schroeter, a consultant with Genovation Group Inc.

“Instead of fuel switching, storage can be used for some power plants as a physical hedge to deal with gas volatility. These strategies make sense in today’s volatile market. Before storage was used just for peaking plants. Now it may be more interesting for base load too,” Schroeter says.

But with the boom in gas-fired electric power plants and just one new gas storage facility on the books, will there be enough capacity to serve demand? Experts are divided.

“The market is not talking about a lot of new gas storage,” says Kevin Petak, director of energy modeling, Energy and Environmental Analysis, Arlington, Va. “Plans for storage are not keeping up with the gas market growth over the next decade.”

Total capacity of underground storage has hovered around 8 tcf for decades, rising to 8.23 tcf in 2000, only slightly above the 8.17 tcf reported in 1998.

Prior to approval of the Stagecoach project, six gas storage applications were pending at FERC, says spokeswoman Tamara Young-Allen. One application is for a permit to expand capacity, and the remaining four applications are seeking permission to expand boundaries that won’t change overall capacity.

Consumption rising
Yet natural gas consumption is increasing 2.3%/year driven by new power plant development. Energy Information Administration estimates electric generators account for 57% of the increase in domestic natural gas consumption. Last year, 28% of annual gas demand was related to electricity.

Surprisingly, despite expectations of rising demand from new gas-fired power plants, EIA economists don’t believe there is a need to rush into building new gas storage capacity.

“The gas infrastructure is adequate for reasonable uses today. What’s causing the problem is the volume of gas in storage—not the capacity,” says Bill Trapman, leader of the EIA’s natural gas team.

Gas in storage is projected to fall to an all time low by the end of this year’s heating season. EIA expects gas in storage to reach 689 bcf by Mar. 31, the end of the this year’s heating season.

Such an end-season level would be 38% below the previous 5-year average and the lowest ever recorded by EIA, says Dave Costello, author of the agency’s monthly short-term energy forecast. The previous 30-year low of 758 bcf was recorded at the end of the 1995-1996 winter.

“Continued growth in gas demand has caused an imbalance that has brought gas storage to its lowest level since 1976,” Peter Fox-Penner, a principal at the Battle Group Inc., told a congressional committee in January. “The reduction of this storage buffer has increased both the level and volatility in natural gas prices.”

Spot gas prices late last year were an eye-popping $10/Mcf in many markets, but have since settled back to $5-6/Mcf.

Despite EIA’s insistence that capacity is adequate, the electric power industry believes more is needed, especially high deliverability storage that can serve gas-fired power plants. Most new combined cycle power plants owners haven’t gone to the expense to add the fuel switching capabilities prevalent in older generation plants.

Fuel switching cost
Installing the capability to burn No. 2 distillate backup on a new combined cycle plant adds about $50/kw to the capital costs and increases operation and maintenance costs, says Schroeter. When burning fuel oil, the catalyst used in air pollution control devices gets dirty quicker and must be replaced more often, he explains. Air permits also take longer to obtain, adding upfront costs.

After regulatory changes separated the storage function from distribution and transportation in the early 1990s, local distribution companies (LDCs) had little economic incentive to develop new facilities, explains Guy Buckley, senior vice-president, Gulfstream Natural Gas System LLC, a joint venture with Duke Energy Corp. and Williams.

In addition, unseasonably mild weather for several winters on top of a long-running gas surplus put storage on the back burner. With plenty of $2-2.50/Mcf gas for most of the 1990s, capital investment for new storage dried up and plans for storage expansion were put on hold.

“This led to a quiet period in storage development,” Buckley says.

LDCs historically have used storage to serve winter peaking needs and to balance pipeline supplies. Power plant needs are different from LDCs. They ramp up and down very quickly, reflecting significant variations in customer demand. Gas is needed on demand.

Relying solely on pipeline gas could be too expensive, particularly under firm contracts. But less costly interruptible tariffs are more risky today given the rapidly increasing demand for gas, the associated price spikes, and lackluster supply response.

“Storage will be an important elemental need for power plants going forward,” Buckley predicts.

Storage is expected to play a more dominant role because of high deliverability facilities that can provide injection or withdrawal services on an hour’s notice. High deliverability storage is attractive to power plant owners who need to power up and down quickly during peak demand and to marketers who want to take advantage of volatile gas prices.

“A lot more power marketers are talking to us now. They are looking for storage facilities with numerous pipelines to optimize trading,” Buckley says.

Duke Energy Gas Transmission Co. is developing high deliverability capability at its Egan, La., storage facility. The company applied to FERC in February to expand Egan’s capacity to 21 bcf from 15.5 bcf. By 2005, the company expects to have 16 bcf of working storage capacity there. The storage facility, being developed to serve a number of proposed power plants in the region, can accommodate big swings in demand for gas with 1 hr notice.

Egan officials are asking FERC for permission to install new compression to increase the average injection rate to 800 MMcfd from 600 MMcfd. Existing deliverability will be maintained at 1.5 bcfd, according to the FERC filing.

Duke is also developing two other high deliverability storage facilities in Moss Bluff, Tex., and Copiah, Miss.

However, the only new storage facility recently permitted by FERC is the Stagecoach storage field being developed by Central New York Oil & Gas Co. LLC, a unit of eCORP. Another affiliate is developing a 520 MW combined cycle gas-fired power plant adjacent to the field.

While Duke’s expansion applies to a traditional salt cavern, eCORP’s new storage facility is high deliverability reservoir-based storage. The field was developed using proprietary technology that permits use of existing underground gas formations that previously would be considered too “tight” (low porosity or low permeability) to be good storage candidates, Thrash says.

The company has already applied its high deliverability technology to the Stuart storage facility in Oklahoma. Stuart is even “tighter” than Stagecoach and has been in operation for 5 years. It has a withdrawal rate of 300 MMcfd.

Gas can be withdrawn at a rate of 500 MMcfd and injections made at 250 MMcfd. The facility will be able to cycle from maximum rate injections to maximum withdrawals in a few hours, Thrash says.

“The field will be ideally suited for meeting the rapidly changing demands of the gas-fired electric generation market that is driving much of the growth in natural gas demand in the Northeast,” according to the FERC filing.

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