Within the larger context of expanded capacity and a newly unbundling transmission/storage system, Sempra Energy’s Southern California Gas Co. utility has identified potential future constraints on its intrastate transmission pipeline system in the Imperial and San Joaquin Valleys where power plants and large industrial customers operate. These areas are potentially tight only on a seasonal basis, such as the summer in Imperial and winter in the San Joaquin valley, according to SoCalGas’ Steve Watson, capacity planning manager, who spoke Tuesday at a GasMart/Power panel discussion in Reno.

“We’ve told noncore customers in open season processes if they are willing to sign long-term contracts for specific backbone quantities with take-or-pay provisions, and we get sufficient interest in subscriptions, we will expand those systems,” said Watson, who shared the program with Bill Wood, the California Energy Commission’s chief natural gas forecaster, in discussing “Natural Gas Infrastructure and Margin Capacity in the California Market.”

Both speakers also discussed liquefied natural gas (LNG) as a potential wild card that might displace the need for some added interstate pipeline capacity going into the northern half of the state. “We’re looking at LNG coming in as an additional supply source and if it can meet the requirements into California itself, and if not, into North Baja as an additional supply to compete for the state’s market,” Wood said.

Watson said that from SoCal’s perspective additional supplies are good, but the utility is “not necessarily going to expand its intrastate system to accommodate it,” adding that what he called a “mismatch” is a good thing from a California utility ratepayer’s perspective.

“If you have 9 Bcf of gas that could potentially come into your system, the gas that we’re ultimately going to have to fire is beating each other up through price competition,” Watson said. “So that is why I think it would ultimately be good for Southern California if we had LNG. We think the market will ultimately decide.

“We’ve identified three viable places to bring gas into our system — one off the California coast, another at Los Angeles Harbor and a third along the North Baja coast. We’ve told all interested LNG suppliers that if they are willing to cover all the interconnection, safety and environmental costs, then we are willing to interconnect with any LNG supplier, and we would be willing to do any detailed studies needed by those suppliers, and in fact, we already have one under way. So, we’re more than happy to have an LNG supplier hooked up to our system.”

In response to questions about the northern half of the state needing more storage longer term, Watson also thinks SoCalGas’s 115 Bcf of underground storage could handle the added need through displacement, and in fact, under the new restructuring of the SoCal system, anyone connected to the PG&E, Kern or Mojave pipeline systems can get their storage needs met by SoCal. “We’ll have a specific tariff in place to offer deliveries that will supplement our storage capabilities,” Watson said. “And our storage is a lot cheaper than PG&Es or Wild Goose [merchant underground storage].”

However, the long-term adequacy of California’s natural gas transmission pipeline and storage system will be driven by the timing and location of new gas-fired electric generation throughout the western states.

Wood was less sure of the overall adequacy of the system longer term than his co-presenter, Watson, who categorically said the southern half of the state will have a margin of at least 20% and a load factor that will average about 70% in future years. Beyond a 20% level of slack capacity, Watson doesn’t think utility ratepayers should pay for additional capacity.

“From my perspective, when we have a 70% or 80% load factor, we have plenty of capacity to meet the needs of consumers,” Watson said. “I don’t think it is particularly prudent policy for California or for the California ratepayers to keep on building more slack capacity in our system just so interstate suppliers can have a place to dump their supplies when primary shippers on the system, the electric generators, happen to be off line.”

Both agreed that when and where new power plants are located — both in and around California — will be a key to infrastructure needs. In addition, Wood said the southwestern corridor created by the El Paso Natural Gas Co. and Transwestern interstate pipelines will have a major impact, too, much of which is being anticipated by SoCalGas’s current 375 MMcf/d capacity increase that will push its takeaway capabilities close to the 4 Bcf/d mark.

In terms of supplies coming into the state, Wood’s forecast for the next 10 years is that supplies will increase from Canada, the Rockies and Mexico, decrease from the Southwest and stay flat among California’s in-state producers. The current state forecasts do not factor in any liquefied natural gas (LNG); those supplies will be included in the next forecast, Wood said.

“Actually, in the next 10 years, capacity is going to increase about 150% in what we call the El Paso-Transwestern corridor with all of the new electric generating capacity under construction or planned in southwestern Arizona and north Mexico,” Wood said. “Our feeling is that we need slack capacity on our system in order to meet the needs for (volatile) demand, particularly like we had a year and half ago when the prices spiked so high.”

In contrast, Watson said the 2000-2001 period was a “perfect storm” that is not likely to reoccur any time soon, so the energy infrastructure should not be overbuilt to meet a once-in-a-century situation. In late 2000-early 2001, if he were asked about sufficiency of SoCal’s capacity, he would have said, “I don’t have as much as I would like.” Today, he says the answer is “we have more than enough capacity for the future.”

Even in facing the “perfect storm” of events that converged in 2000-01, Watson said there was “plenty of slack” in the gas utility’s system, which at the time had 3.5 Bcf/d of transmission pipeline system and 115 Bcf of storage capacity.

With the added 375 MMcf/d capacity that will be in place by this summer, and the restructuring to operate the in-state network more like an interstate pipeline, Watson said he doesn’t see the need for any more “fixes.” He particularly stressed that the addition of firm, tradable capacity rights on the backbone system will help mitigate against what he called the “basis blowout in prices” that occurred in the fall of 2000.

That price spike proved temporary because by last June wholesale prices were back down to more historical levels, said Watson, who noted that the utility enters this spring with nearly 55 Bcf additional supplies in storage and the 11% increase in pipeline capacity at a time when electricity loads on the SoCal system are dropping.

“We think there are a lot of factors that are going to decrease the demand our system,” he said. “Electric generating plant demand is going to go way down compared to where it has been. Electric generation demand went way up real fast, and it is going to go way down just as fast. The number one factor is that we will have more normal hydro-electric supplies. Longer term, the newer, lower heat rate generating plants that tend to be off of our system will be more in demand, lowering demand for the older, higher heat-rate plants that tend to me on our system.”

In the future, if SoCal does get tight on capacity, market demand should decide what additions are made. Additional capacity increases become “more and more expensive, so we’ll look at those situations on a case-by-case basis,” Watson said. “There are diminishing returns to having too much slack capacity.” He added that SoCalGas will be glad to add so-called “takeaway capacity” for any shipper who is willing to pay for it through long-term firm deals.

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