Every year by October 31, injection of natural gas into U.S. storage ends. This year, the amount of gas set aside rose 7.8% above the five-year average to total almost 3.3 trillion cubic feet (Tcf). The gas withdrawal season is now here. But just as people were raking leaves across America, investors were raking in profits as gas futures soared above $7 per million Btu on Nymex. With full storage implying adequate gas supply, why are prices still so high? Would more storage capacity mitigate the price? The last available data from the Department of Energy, for 2003, counted 415 storage facilities in the U.S. with aggregate working gas capacity of 3.9 Tcf. Another 4.1 Tcf remains behind as cushion or base gas that stays in storage for operational reasons. "Currently, from a national perspective and assuming average weather, storage appears to be adequate," the Federal Energy Regulatory Commission (FERC) said in a September 2004 report. But analysts fear there may not be enough storage capacity in the right places to maintain reliable deliverability and to moderate price volatility. "...It may be easier for local distribution companies to simply purchase gas at (spot) rather than invest in facilities to mitigate volatility," FERC reports. Still, no one doubts that longer-term, more storage will be needed as gas demand grows, and with the advent of increased supplies coming from liquefied natural gas (LNG), more storage will be needed along the Gulf Coast. The market is responding. In the same week this past October, FERC received two applications for new-build, independently operated storage projects, one for a Mississippi facility proposed by Caledonia Energy Partners LLC of Dallas, the other proposed for southwest Louisiana by EnCana, based in Calgary. "A lot of people are getting interested in storage who weren't before, or they are coming back," says John Hopper, president of Falcon Gas Storage Co., which is preparing applications to FERC that will be filed next year. The Houston company has 22 billion cubic feet (Bcf) of working gas capacity in operation in Texas and another 78 Bcf in various stages of development in several other states. All of its facilities are and will be in depleted oil and gas reservoirs that have been converted for storage. Some 85% of U.S. stored gas is in these depleted fields, where the gas can be injected and withdrawn only once or twice per year. About 10% of storage lies in aquifers that tend to have higher deliverability rates than the reservoirs. The balance is stored in salt caverns where the gas can be injected and withdrawn more often in a given year, up to eight times. "I think with these high prices, the market is saying we don't have enough gas in storage," says Hopper. "The U.S. has about 3.2 Tcf, but what does it really mean? The record storage withdrawn through the winter is about 2.6 Tcf, so you need the capability to get more gas out of existing storage, or you need more storage. I do think we need more withdrawal capacity than the 2.6 Tcf that industry has demonstrated. It's a question of when, where and how much?" Project economics Not surprisingly, the value of storage appears to be rising right along with rising natural gas demand in North America. In addition to the utilities that manage most of the nation's gas storage, independent third-party storage such as that operated by Falcon is gaining market share. Gas demand used to be seasonal, with injection occurring in summer and withdrawal in winter, but those seasons have changed. Summer competition has grown between gas needed for electric generation and gas being injected into storage for the approaching winter. More or less continuous injection from April Fool's Day through Halloween has been shortened to April, May and June (very little in July and August), and it resumes in September and October. Winter gas-fired electric demand is now competing with winter storage deliverability and peak-day demand. Storage management and development of high-deliverability storage provide local distribution companies a physical hedge "and actually serve to mitigate daily and seasonal price volatility," says a recent study of natural gas infrastructure by Energy and Environmental Analysis Inc. The firm says when price basis differentials rise enough, construction of new pipelines and storage facilities can be justified. It estimates $24 billion needs to be spent on pipelines and storage by 2020, not counting what is required for routine maintenance and replacement, or the Alaska and the Mackenzie Delta projects. Because FERC also thinks building new storage may help reduce price volatility, "there may be a public policy interest in encouraging more storage development," it says. But that is easier said than done. Some recently proposed projects have been canceled or put on the back burner due to lack of contractual support from customers, or due to environmental opposition. If market power cannot be shown, FERC typically denies the storage developer market-based rate authority. But FERC is studying ways to encourage more storage, noting that the loss of a vibrant trading sector means fewer customers are willing to pay for the trading benefits of storage. Project economics are challenging, especially for the salt cavern facilities built outside the Gulf Coast region. Some critics claim developing independent storage is too risky to finance because unlike pipelines, there are no long-term contracts of 10 to 20 years. Traditional cost-based storage rate design does not encourage more storage, they say. The cost of a new salt cavern storage facility is about $10- to $15 million per Bcf of capacity, one source estimates. Too, the cost of acquiring and injecting base gas is high now. Geology is a factor for depleted reservoirs, particularly in the Northeast and desert Southwest, where few depleted reservoirs meet the technical criteria. The National Petroleum Council's wide-ranging gas report, released in September 2003, said U.S. electricity demand rose 31% from 1990 to 2002. Though that buildup is not expected to continue at the same rate, it will increase nevertheless. The NPC study therefore estimated another 700 Bcf of gas storage in needed in the U.S. and Canada by 2025, which translates into adding an incremental 35 Bcf annually. Storage is needed most in the mid-Atlantic region and Northeast where the biggest U.S. markets are. New storage plans Despite market and financing challenges, several new storage facilities and expansions have been proposed. Falcon Gas Storage pursues a strategy of modifying existing facilities that it acquires and building new ones. It has modified facilities to allow more working gas to be withdrawn vs. the cushion gas left in storage, by drilling more wells at the facility and adding compression to move more gas into area pipeline interconnects. At its Lone Star facility in North Texas, for example, compression was available for gas injection but not withdrawal, so Falcon modified it to allow compression in both cases. At its Hill Lake unit west of Dallas, which is taking more gas from the burgeoning Barnett Shale play, the company doubled capacity such that it can withdraw 10 Bcf during a winter, up from 5 Bcf before. It also increased the peak-day withdrawal rate to 175 million cubic feet per day from 45 million. These changes cost the company about $30 million of investment. Next up is the 45-Bcf MoBay facility proposed for onshore Mobile Bay, Alabama. The environmental impact statement and engineering assessments are still under way before a formal application can be sent to FERC this coming spring or summer, Hopper says. MoBay's new onshore facility will take gas stored in a depleted offshore field. The first phase will allow withdrawal of 12 Bcf a day. Operations are scheduled to start in fall 2006. "When we first came up with the MoBay idea, all these LNG projects weren't even a gleam in anyone's eye. We saw the Florida market as our primary target," Hopper says. Unocal regards gas storage as so important that it is a separate profit center, driven not by its equity gas position, but by third-party business, says Joe Blount, president of Unocal Midstream & Trade Co. in Sugar Land, Texas. UMT has interests in 67 Bcf of storage capacity today in the U.S. and Canada. These assets dovetail nicely with its gas marketing business. UMT had been adding capacity. This past July it held open season to gauge interest in a fifth salt cavern now being mined at its 3-Bcf Keystone facility near Kermit in West Texas. The first four caverns have sold out firm capacity and can deliver more than 300 million cubic feet a day. The fifth comes onstream in April 2006. The sixth and seventh caverns have been proposed. In October UMT began an open season to determine interest for 6 Bcf of storage at its proposed greenfield Sabine Pass facility near Beaumont, Texas. Construction is expected to begin in 2006, with actual storage injections in 2008. Plans call for it to have 400 million cubic feet per day of deliverability from the old salt dome structure. Sabine Pass is positioned to serve the proposed LNG regasification terminals and current producers along the Texas and Louisiana coasts. Bi-directional interconnects will provide access to Texas intrastate and interstate markets, Mexican gas markets and the Sabine and Houston Ship Channel industrial corridors, Unocal says. And in first-quarter 2005, UMT will initiate another open season to assess market need for its proposed Windy Hill property in Morgan County, northeast Colorado. It is now drilling a 6,500-foot test well there to determine feasibility of developing the site, which would be the first bedded-salt gas storage facility in Colorado. The test will determine the properties of the salt formation and the brine injection capacity of the Cretaceous sands. If the geology and technology are right, the market says it wants this facility, and state and federal approvals are forthcoming, Phase I would go into service by late 2007, says Blount. Windy Hill will offer 3 Bcf of working gas capacity, an injection rate of 100 million cubic feet a day and a withdrawal rate of 400 million a day. The ultimate goal is to provide 9 Bcf of high-deliverability storage for gas shippers in the Rocky Mountain region. Caledonia petitioned FERC in October to build and operate a facility in northeast Mississippi straddling Monroe and Lowndes counties with an interconnect to Tennessee Gas Pipeline. It is to be operational by spring 2006, says Jim Goetz, president of Caledonia. The Caledonia Storage Field will have 11 Bcf of capacity with a withdrawal rate of 330 million cubic feet per day from the depleted gas field. Caledonia will own it 100% and finance it with bank debt, project finance and some private equity, Goetz says. Also in October, EnCana's storage subsidiary applied to FERC for Starks Gas Storage LLC to be built in Calcasieu Parish, Louisiana. Two salt-dome caverns will be converted to storage, with an in-service target of third-quarter 2006. Storage capacity will total 19 Bcf with a withdrawal capacity of 800 million cubic feet a day. Starks will connect with several major pipelines in the area. EnCana is already North America's largest independent gas storage operator. "The timing for more storage seems to be right," says Caledonia's Goetz. "We're seeing a greater urgency in energy infrastructure. With the lead time it takes, by the time we build it, storage will be at a premium. The biggest obstacle in this market is the price you have to pay to inject base gas." Falcon's Hopper notes growing interest, saying that some energy hedge funds and private equity funds are now taking a fresh look at gas storage facilities as investments.

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