a fortunate few, opening up competitive options even
of 1998.With a fountain pen and a flourish of promises, California Gov. Pete Wilson ushered in the future on September 23 when he signed California's latest legal missive on electric utility restructuring, known as Assembly Bill (AB) 1890.
"Every time a resident of this state flicks on the electric switch, they pay 40 percent more than residents across the United States," Wilson proclaimed. "The legislation I am signing will end that by ushering in a new era of competition, making California the first state to dismantle its electric monopoly."
Whether the legislation matches such a grand vision remains to be seen, but it certainly moves the process forward by putting into law many of the major industry restructuring policies formulated over the past 30 months by the California Public Utilities Commission (CPUC).
The price of this grand package hasn't come cheap. The changes to the state Public Utilities Code envisioned by AB 1890 include a series of compromises by and guarantees to utilities, industry stakeholders, and ratepayers. Among the promises: the power pool (Power Exchange) and
independent transmission system desired by utilities and regulators; "direct access" competition sought by large energy users; even a
10-percent rate decrease for residential and small commercial ratepayers by 1998, with another 10 percent promised by 2003.
But the biggest promise in the new law, in terms of monetary impact, comes from the willingness of the state legislature to honor the CPUC's pledge that investor-owned utilities (IOUs) would get the opportunity to fully recover all of the costs of their stranded assets. Even municipal utilities gained some assurance of protection of stranded-cost recovery, in return for opening their territories to competition and turning transmission control over to the independent system operator (ISO).
The long debate successfully narrowed down the concept of "stranded costs" (em from the utilities' expected lost revenue streams to the net book value of uneconomic generation resources. But AB 1890 also expands the stranded-cost universe a bit by including union labor transition costs, the buyout of independent power contracts, and more than $700 million in support of renewable resources, energy efficiency, and utility research programs from 1998 through 2001.
Most of the cost of these promises will be bundled into the competition transition charge (CTC), which will be assessed against all current customers of the IOUs, to be paid off by the end of 2001 (except for union buyouts, nuclear buydowns, and remaining power-purchase commitments, which extend beyond that date).
The total cost of this promise (em never fully quantified even after two years of public hearings and debate (em could run up to about $30 billion by the time CTC is fully paid off. Without a big number to fix on, it's almost impossible to say how high the CTC will run on a cents-per-kilowatt basis.
With AB 1890 imposing a rate freeze at June 1996 levels for larger customers, the CTC is best calculated as the difference between the pool energy price, the unbundled costs of distribution and transmission, the costs of ancillary services, and today's energy tariffs. Utilities must collect as much of their sunk costs as possible by 2002 under this system.
Best-guess estimates derived by industry consultants MRW & Associates for the New Energy Ventures power aggregator group range between $0.023 per kilowatt-hour (Kwh) and $0.033/Kwh.
During the transition period (em that is, until the CTC is paid off (em the larger customers will have at their disposal only a few methods to achieve savings on power services compared to their present rates.
One method is to find reliable power supplies that will consistently run below the Power Exchange price. Although the pool itself was originally envisioned as a source of competitive pressure to reduce rates for utility customers, in the near term any difference between the prospective pooled energy price and current power tariffs clearly will be reallocated into the unbundled service offerings (distribution, transmission, and system support, etc.) and the CTCs for stranded assets and public benefits (demand-side management (DSM), renewables, low-income assistance, etc.).
Not knowing the ultimate pool price (em and our best guess is that it will vary greatly by season, by day, and even by hour (em makes it difficult to identify what price from a direct-access commodity seller will result in guaranteed energy discounts.
A second mode of savings would be to somehow avoid the CTC. The CPUC had always intended the CTC to be "nonbypassable" and allocated among all utility customers as of the date of its major restructuring policy decision in December 1995. That meant even direct-access customers would bear the CTC obligation beginning in 1998, and the CPUC would not tolerate exemptions or early defections from the utility system as a "sham transaction" meant to avoid paying the CTC.
When the CPUC formalized an interim CTC policy on April 10
in Decision 96-04-054, its then-president Dan Fessler stated, "We want to impart a clear and unequivocal indication that the CTC be nonbypassable." Fessler's rationale was mainly based on the need to prevent "cost-shifting" of the stranded investment from one customer or customer class to any other.
The CPUC has yet to adopt a final decision on setting the level of an interim CTC, and some observers feel that AB 1890 has made interim protections unnecessary. Nevertheless, the threat of an interim CTC has kept a lid on several attempts to speed up the competitive market in advance of the CPUC's restructuring timetable.
Until passage of the new law, even those that had been pursuing pre-restructuring alternatives, such as self-generation, faced the potential CTC assessment. Attempts to work out exemptions for projects under development, as part of the negotiations over Pacific Gas & Electric Co.'s (PG&E's) docketed rate freeze and accelerated depreciation schedule, were quickly slapped down by Fessler last May in a written rebuke to PG&E president Bob Glynn.
The "nonbypassable" nature of the CTC also appeared to be a hallmark of the second memorandum of understanding (MOU) worked out by utilities, industrials, and cogenerators at the start of the August legislative hearings. This MOU or "Coalition Proposal" (also called "MOU and friends") eventually formed the basis of formal language for AB 1890, which was then unanimously passed by the legislature.
Clearly, the policy of assessing a nonbypassable CTC has been modified by the legislature (em possibly opening up new competitive options for certain players even in advance of 1998. In the hands of the legislature, the term "nonbypassable" is flexible (em something dependent upon the skill of your Sacramento lobbyists. AB 1890 may be fairly characterized as being riddled with exemptions from the CTC levy.
Loopholes and Legalese
Some of the CTC exemptions carry a clear implication of cost-shifting, despite the law's creation of a so-called "fire wall" to prevent the CTC burden from sliding to other customers.
Legalese makes it difficult to determine where the loopholes exist. As Bob Weisenmiller of Oakland-based industry consulting firm MRW & Associates recently said, "It's become a kind of parlor game to guess who the CTC exemptions are meant for and who else might try to use them for their own advantage."
Some exemptions are clearly marked. The major exemptions specified in sections 372 through 374 of the bill cover existing or planned self-generation projects and irrigation districts. New load not served by the utility as of December 1995 is also excluded from the CTC assessment.
Other items excluded from CTC liability include: reductions in energy use due to "normal course of business" such as changes in weather, strikes, moving out of state, and other reasons for lost utility load (em including new energy-efficiency installations, fuel-switching, use of fuel cells, or more efficient repowering of existing equipment. The law specifically preserves customers' right to control energy use on their side of the meter.
What is definitely not protected comes under section 369: "The obligation to pay the [CTC] cannot be avoided by the formation of a local publicly owned electrical corporation on or after December 20, 1995, or by annexation of any portion of an electrical corporation's service area by an existing local publicly owned electric utility." In other words, new municipalization, or "muni-lite" efforts, are liable for the CTC. However, this proscription against territory raiding could be outweighed by other specific exemptions for irrigation districts.
When the legislation applied an exemption from CTC recovery for lost load due to self-generation "committed to construction" as of December 20, 1995, it closed the door to some extent on new projects being slapped together to take advantage of a loophole. In addition to documented proof of commitment, a plant would probably have to be in operation by 1998.
Such projects currently under development include a 3-megawatt (Mw) cogeneration unit for a medical center at the University of California at San Francisco, and a 28-Mw unit at the medical center for the University of California at Davis, even though a smaller unit for the University of California at San Diego might not qualify. Dian Grueneich, an attorney representing the State of California in energy matters, argued that such exemptions were justified by the substantial monetary investments made by the University of
California schools to plan their self-generation projects well before restructuring was envisioned.
In addition, at least a half-dozen large cogeneration plants planned by oil companies, industrials, and other customers have been covered by cogeneration deferral contracts from PG&E. These range in size from a long-deferred 100-Mw self-generation project at the Chevron refinery in Richmond, to a 49-Mw Exxon project at its Benicia refinery, to a 2.6-Mw cogeneration project deferred last year by the state corrections department for the Avendale prison.
Both PG&E and Southern California Edison (SCE) also have generic anti-cogeneration tariffs
in effect (em PG&E's covers up to 100-Mw of potential bypass. How much of that has been subscribed is unknown, however, because the utilities won the right to keep contract information under a cloak of confidentiality.
Under the terms of AB 1890, many of these projects might qualify for exemption if they are ever built.
The bill also allows up to a 20-percent capacity expansion at existing self-generation units (em including those able to provide "over the fence" service to neighboring loads. This could represent a new business opportunity.
A few analysts have pointed out that this competitive option appears limited both by the fact that most in-state cogeneration opportunities have long been exhausted, and by a provision in the bill that the load served by the system expansion has to be "affiliated" with the owner or operator of the cogeneration unit.
"Unaffiliated" load, on the other hand, will remain liable for the CTC only until June 30, 2000; everyone else must pay until 2002. So there could be at least an
18-month CTC exemption for localized cogeneration expansion opportunities.
Two other specific exemptions were afforded to potential expansion of "load served by preference power purchased from a federal power marketing agency or its successor." This language applies to the Bay Area Rapid Transit district (BART) in metropolitan San Francisco, and the University of California-Davis campus, which currently buy power from the Western Area Power Administration (WAPA) (em and in the case of BART, from the Bonneville Power Administration also (em and expect to increase their purchases in the future.
This exemption also appears to offer loopholes for other customers (em possibly including water districts that have taken over a 100-Mw WAPA allocation given up by members of the Northern California Power Agency and the City of Alameda.
The bill does not name eligible agencies, but states that related energy purchases must be "preference power ... used solely for the customer's own systems load and not for sale."
An interesting element of the BART exemption is that lost utility revenues will be collected from all ratepayer classes (em apparently the only instance of a breach in the law's "fire wall" against cross-class subsidization.
Many people believe there is an unlimited exemption for installing microgeneration units of 1 Mw or smaller, but no such exclusion appears in the legislation. What the measure does allow is an application to the CPUC for a "financing order" for customers to use the CTC bonds to cover transition costs associated with installing new microgeneration. How regulators will respond to such requests is uncertain.
The bill however, does specifically exempt improvements to existing cogeneration and allows the installation of fuel cells to reduce CTC-compromised load, unless the California Energy Commission (CEC) holds otherwise.
By far the most far-reaching CTC exemptions fall to irrigation districts (em a total of 185 Mw of CTC exemptions phased in over five years (em beginning in 1997, one year ahead of general direct-access competition. Some analysts and utilities claim these exemptions will "cost" up to $87 million, with the liability spread to other customers within the commercial/ agricultural rate classes that must bear the CTC. Others, however, argue that restrictions on the exemptions will limit their economic impact.
For example, the bill says that costs associated with public-agency CTC exemptions can be collected from other customers (presumably through the public benefits charge), but only $50 million of any balance remaining after 2002 would be eligible for recovery.
The lion's share of the exemption (em 75 Mw (em goes to the Merced Irrigation District (MDID), which only recently joined the ranks of irrigation districts that also serve as utility retail power sellers. Garith Krause, MDID's chief financial officer, says the exemption was part of a compromise meant to protect irrigation districts' independent, legal, unlimited authority to act as retailers [Water Code Sec. 22115].
According to the CEC, there are at least 67 irrigation districts in the state. Though only four currently sell power to retail customers (em Merced, Modesto, Turlock, and Imperial (em the state water code could allow many others to enter the field.
Many irrigation districts and other water agencies were preparing for competitive power opportunities through aggregation plans being formulated by the Association of California Water Agencies. Although most of these districts and agencies (em such as the 2.5 Mw Delano-Earlimont Irrigation District (em have small individual loads, heavy use in summer peak periods causes a higher-than-average utility rate. Given the early-entry advantages of AB 1890, several of these districts and agencies could combine with local customers to take advantage of their share of these CTC exemptions.
MDID appears to be the big winner from this exemption, along with a few customers it has targeted in the town of Livingston, where it has already spent about $2.5 million to build a substation and extend distribution lines to serve the Foster Poultry Farms facility and adjacent energy users.
Although load covered by the CTC exemption must be generally within MDID's territory and served by district distribution facilities, the law also allows MDID to expand its reach to cover the nearby Castle Air Force Base.
Krause notes that while more than 300 Mw of electric load exists in eastern Merced County, "it's unlikely we could have gotten it all" (em certainly not without fighting PG&E over collecting the CTC. The 75-Mw CTC exemption afforded by the new law will be opened up 15 Mw each year of the exemption period, so MDID should be able to compete more aggressively later.
The CEC will allocate the other 110 Mw pro rata to districts throughout the state, according to the number of districts in each IOU territory (although most of these districts lie in PG&E territory). Districts can apply for allocations between 8 and 40 Mw, but must provide a "detailed plan" to the CEC. The major limits are that loads served must lie within the district territory, and 50 percent of each year's allocation must be applied to agricultural pumping load.
Still, the remaining 50 percent represents a significant amount of electric power that could be used to directly serve agribusiness customers in those districts. Not only could direct-access or aggregation opportunities reduce the commodity cost of energy for pumping, compared to utility agricultural rates, but exemption from the CTC could provide another $0.02 to $0.03/Kwh margin to irrigation districts.
In a separate provision, water agency members of the Eastside Power Authority and the Southern San Joaquin Valley Power Authority also receive a CTC exemption for pumping loads (em giving a boost to their efforts to bypass SCE.
Who else will take advantage of these exemptions? Certainly the other major irrigation district/ utilities (em Modesto and Turlock (em are already figuring out how to format their competitive plans to meet the requirements of the law and win a major share of the CTC exemption.
The Imperial Irrigation District (IID), however, proves more reticent. According to IID superintendent of generation Jim Mordah, IID "doesn't want to get anybody mad at [them]" by stealing customers from neighboring IOUs (em even though nearby Palm Springs is practically begging for a way to bypass SCE.
Large food-processing plant managers in those districts could also form alliances to turn those exemptions into power-cost savings.
Meanwhile, the state's irrigation districts are contemplating their options. Chris Mayer, assistant general manager for marketing at the Modesto Irrigation District, says that several energy consultants have been spotted driving up and down Highway 99 through the Central Valley, knocking on doors to offer their services to perplexed districts. t
Arthur O'Donnell is editor and associate publisher of California Energy Markets, a newsletter that closely follows the California restructuring effort.
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