Gas storage levels could enter the winter heating season at record highs, but EnCana Corp. told FERC this week that high price differentials between injection and withdrawal season months show that the gas market is demanding that even more storage capacity be added to the marketplace. There are indications that storage capacity may be becoming inadequate to handle a colder-than-normal winter, EnCana said.
“Despite unusually high differentials between near-term gas prices (spot and near month) and winter futures prices, and therefore, unusually high margins to be achieved by injecting gas, it is unlikely the industry’s inventories will exceed 3.3 Tcf unless warm weather early in November permits an extension of the injection season,” EnCana said in comments regarding FERC’s State of the Natural Gas Industry Conference later this week and FERC staff’s Report on Natural Gas Storage.
EnCana pointed to a “significant gap” between working gas capacity, as stated by operators, and “effective capacity,” or what can be injected and withdrawn in a year.
“Some of the high seasonal gas price variability of recent years may be indicative that our storage infrastructure is now being used at close to its capacity even in the absence of a significantly colder than normal winter,” EnCana said.
FERC staff said in its report on gas storage that it believes there is 3.5 Tcf of practical working gas capacity and another 200-500 Bcf of potential working gas capacity that could be “reengineered and used.”
However, EnCana said what FERC staff failed to consider is that the “empty” level of working gas may be “substantially higher than the ‘zero’ level.”
EnCana said the maximum amount of gas that has ever been injected or withdrawn in a season is only 2.5 Tcf. Furthermore, the record was set during the last four years and was accompanied by extreme seasonal price variations.
“This evidence suggests that effective [working gas capacity] may be in the range of 2.6 to 2.7 Tcf and that this level of inventory build and draw may not be achievable without extreme seasonal price swings.”
The industry has been under the impression that there was more working gas storage capacity because capacity estimates may be out of date or may have been incorrectly calculated, EnCana said. “Engineering estimates of [working gas capacity] do not usually account for practical, contractual and market limitations on the ability to access the capacity.”
The bottom line is that FERC should adopt policies that encourage more storage development, said EnCana, which owns about 38 Bcf of storage capacity in two facilities, Wild Goose in California and Salt Plains in Oklahoma.
What it shouldn’t do is promote development of a gas storage reserve, according to EnCana. FERC’s notice for the conference this week mentioned the storage reserve. Others inside and outside the industry also have discussed the possibility (see Daily GPI, Oct. 13). Such an idea, however, is “not likely to result in timely, cost effective development of new [storage] capacity, and in fact would likely discourage the development of ‘effective’ and market responsive capacity,” EnCana said.
Storage development already is being discouraged by various regulatory policies and a wide range of other factors, EnCana noted. The negatives include poor rates of return for storage operators, few creditworthy customers, conflicting signals from state regulators regarding utility hedging and long-term supply commitments, over-regulation of storage, a lengthy permitting process, and a reluctance to permit market-based rates and flexible services.
Red Lake Gas Storage also filed comments this week with FERC regarding the upcoming State of the Natural Gas Industry conference. Red Lake’s proposed salt cavern storage field in Mohave, AZ, was put on hold last year after the Commission denied it market-based rate authority after concluding that the facility would have too much market power in the Southwest, where there is very little gas storage capacity (see Daily GPI, June 5, 2003).
Red Lake told the Commission this week that it should adopt “more flexible procedures for determining whether competitive market forces will adequately constrain rates to be charged by new storage projects.” Red Lake suggested that storage operators be allowed to charge market-based rates subject to a periodic regulatory review. It also recommended that the Commission make it clear to storage operators not allowed to charge market rates that they still are “free to use seasonal commodity pricing differentials in negotiated rate pricing of storage services.”
Other factors that have discouraged independent storage development, according to EnCana, include a competitive situation with the incumbent utility. “Tactics that can frustrate full integration of independent storage into the delivery system of incumbent [utilities] include: oppressive interconnection requirements; discriminatory transportation tolling of storage volumes; and refusing independent storage the ability to compete for new balancing or core storage demand.”
EnCana said FERC has been headed in the right direction with its pro-market approach. “It would be a giant step backward,” the company added, “were the Commission to adopt any policy that distorted the market for storage services or excluded willing investors. An example would be a policy that allowed traditional cost-of-service utilities to pre-build ‘reserve capacity’ at ratepayer expense.”
EnCana recommended that FERC continue to approve storage expansions at cost-of-service storage operations in conformance with its rolled-in rate policy and “thereby encourage efficient expansions of existing facilities without subsidization by existing ratepayers.”
As a good example of storage market design, the company cited California’s policy in the Pacific Gas & Electric service territory, which has allowed the development by EnCana of 1 Bcf/d of incremental withdrawal capability directly connected to the PG&E system but with no financial contribution by utility ratepayers.
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