Early on in the debate, the legislature had signaled the commission that it would need the blessing of lawmakers to pursue its agenda.This past August, during the waning days of a two-year session, the California Legislature unanimously passed a landmark bill to deregulate the state's $23-billion electric utility industry.
The new law, known as "Assembly Bill (AB) 1890, largely reaffirms the broad outlines of the December 1995 Final Policy Decision issued by the California Public Utilities Commission (CPUC). It ratifies the CPUC's plan for a Power Exchange to create a wholesale electricity market, and an independent system operator (ISO) to manage operation of the transmission grid. It also calls for state-backed bonds to "securitize" stranded costs and secure a promise for a 10-percent rate reduction for residential and other small customers.
Overall, AB 1890 covers an enormous range of issues (em from market structure to direct access (em with special incentives for various players:
s Utilities (em receive strong assurances of their ability to recover $20 to $30 billion in stranded
costs over a four-year period
(municipals must play in the new market to get this authority).
s Large Customers (em get direct access in the near term, a shorter stranded-cost recovery period, and an exemption from paying stranded costs in certain areas.
s Labor unions (em are guaranteed that worker retraining and severance will be included in stranded costs, and benefit from a provision that requires buyers of divested plants to maintain labor agreements for two years.
s IPPs (em receive assurances that existing contracts will be respected, some certainty as to the method of calculating avoided cost, and utility financial support of both new and existing projects.
s Small customers (em are guaranteed a rate freeze and a mechanism that provides rate reductions by securitizing a portion of the stranded costs, as well as standards for system reliability and protections against consumer fraud by new suppliers.
All in all, the legislative committee remained remarkably diligent in attempting to comprehend the implications of each special provision inserted in AB 1890. But since the measure was crafted with the help of dozens of interest groups and their lobbyists, AB 1890 emerged ultimately as the bill with something for everyone.
Is the Small Customers' 10% Rate Reduction for Real?
The legislators had let it be known early in the game that a rate freeze would not be sufficient politically; instead, they had insisted that small customers must see a rate decrease (em in both nominal and real terms. So, rather than threaten utilities with reductions in stranded-cost recovery to achieve this rate relief, the rate reduction for small customers is paid for by securitizing a portion of each utility's stranded costs, using up to $10 billion in revenue bonds issued by the State Infrastructure Bank.1 The utilities will receive the proceeds of the sale of the bonds, write off that portion of stranded assets, and collect interest and principal payments from small customers over a 10-year period. The utilities' rights to these payments will be transferred to the Bank.
As the utilities write off the "securitized assets," replacing them on the balance sheet with the cash proceeds from the "sale," their annual revenue requirement associated with the recovery of capital and return for those assets is reduced. The large customers agreed that the revenue requirement savings could be targeted to small customers, resulting in an immediate 10-percent decrease for that class. The legislature further mandated an additional 10-percent decrease beginning in 2002; this insurance should not pose a problem for the utilities if they have truly recovered their stranded costs by that time.
State Senator Peace claimed that the Infrastructure Bank would be able to issue debt at a lower cost of money than the utilities would charge for carrying the asset on their books. It turns out, however, that nearly all the benefit of the securitization approach will come from extending the repayment term; the cost of money differential is slight since the CPUC had already reduced the rate of return on utility stranded assets to a debt-based return.2
The securitization program became very important since TURN (Toward Utility Rate Normalization) was most unhappy about the willingness of the conferees to accept a freeze on allocating stranded costs among customer classes. TURN had fought hard to limit small ratepayer liability to 35 percent of the stranded costs. The current CPUC-approved rate design, with an allocation of stranded costs based on an equal percentage marginal cost (EPMC), mandates a higher cost responsibility level on small customers. (Small customers would pay for stranded costs based on their EPMC share of overall systems costs, rather than their smaller share of generation costs.) Large customers threatened to walk from the process if the legislature were to adopt TURN's proposed EPMC based only on generation. In the end, the conferees argued that the rate relief for small customers promised by securitization would provide an offsetting benefit to the cost allocation freeze. TURN ultimately agreed that the securitization program would provide an actual 10-percent reduction.
How Will Utilities Recover 100 Percent of Stranded Costs?
In return for some type of rate freeze, the utilities received strong assurances for recovering their $20 to $30 billion in stranded costs over the transition period (January 1, 1998 to December 31, 2001). AB 1890 also expands upon the CPUC's definition of stranded costs to include worker retraining and displacement compensation, initial support for renewable energy technologies, and reliability-related capital additions made prior to December 31, 2001.
Ostensibly, all going-forward costs, such as operation and maintenance costs, fuel and fuel transport, and administrative and general costs, will be recovered via the Power Exchange or from contracts with the ISO for units run for system reliability.3
With stranded costs estimated at between $20 and $30 billion, the resulting competition transition charge (CTC) could range from 2 to 4 cents per kilowatt-hour (¢/Kwh). Naturally, some parties sought exemptions from the "non-bypassable" CTC obligations.
Parties who believed that they enjoyed historical rights to bypass the utility system argued that it was unfair to include a CTC on those transactions. This group included cogeneration projects by the major oil companies, which had either come on line, committed to construction, or agreed to deferral. Similarly, irrigation districts claimed a privilege to exercise little-used but preexisting rights to serve customers outside their districts. Customers who had obtained the right to replace utility power with service from federal power marketing agencies also claimed exemptions from the CTC. By agreeing to these exemptions, the utilities undoubtedly viewed losing these CTC contributions as a reasonable business risk.
In the end, the legislative committee did not go as far as some parties had negotiated on how such exemptions might work, but left considerable discretion on this issue with the CPUC.4
Concerned that small customers might bear the cost of these exemptions, TURN and other consumer advocates argued for some assurance of protection from any additional cost-shifting. Toward this end, AB 1890 provides a "fire wall" to prevent the exemptions provided to large customers from being recovered through small customers.
Constructing this fire wall required making a determination as to the CTC split between large and small customers. As noted above, the stranded-cost burden was divided 60/40 between large and small customers, respectively. Therefore, any exemptions provided to large customers must be recovered from the remaining customers within the class and as part of the rate freeze.5 Since the potential exists that customers rates can be frozen through March 31, 2002, utilities can only collect the cost of these exemptions if all other stranded costs have been recovered. That is the business risk they calculated they could accept.
What About the QFs?
Though not as vocal as the oil companies, agricultural interests, or manufacturers, QFs (qualifying cogeneration and small power production facilities) received some stocking-stuffers as well.
AB 1890 reaffirms the CPUC's position with regard to contract sanctity for QFs. It also allows for an additional $5 billion in revenue bonds to be issued by the California Infrastructure and Economic Development Bank to assist in the renegotiation and/or buy-out of QF contracts. In addition, AB 1890 ensures that utilities can recover the costs associated with these QF commitments until the end of their contract terms (em until 2028, in some cases. The QFs remain vulnerable only to the extent that their contracts and nuclear decommissioning costs will be the only remaining stranded cost after 2006, leaving them somewhat open to attack.
In addition, the renewable energy community managed to gain some ground, with the
legislation creating a statutory floor for utility investment in renewables. Although the legislation did not create a renewables portfolio standard, as many environmentalists and renewable project owners had been hoping, it does provide the renewables community with a minimum of $465 million in funding over the transition period, with a maximum of $540 million.
A split in the renewables community emerged during the debate, however, over what portion of this funding should be used to support existing as opposed to new projects. Initially, the existing project owners won the debate, having managed to insert language providing for a 60/40 split in their favor. However, at the eleventh hour, as a result of additional pressure, the language was changed to state that, at a minimum, both existing and emerging renewables projects should receive at least 40 percent of the funding, leaving the remaining 20 percent up for grabs. These monies will be allocated by the California Energy Commission.
The renewables also won a favorable interpretation on the phase-in of direct access. AB 1890 provides that if 50 percent of a customer's load is served by a "green" provider, then that customer is exempted from any phase-in requirements. But while the legislation seems to apply only to instate green power, this "instate" interpretation will certainly be challenged by out-of-state suppliers and their instate marketers.
Finally, the legislation helped resolve an outstanding debate over short-run avoided-cost calculations (SRAC) for QFs. Over the preceding year, several parties had attempted to negotiate an index-based method for calculating avoided cost. The independent producers reached agreement with both PG&E and SCE on such a formula, but it was not clear if the CPUC would approve the agreements. Some parties seized the opportunity to codify elements of their proposal as part of AB 1890, ostensibly preempting the CPUC on SRAC reform. The bill provides that SRAC will be based on a starting energy price and indexed periodically to natural gas prices at the California border, thus eliminating regulatory proceedings to determine utility avoided costs.
As would be expected, the legislature included many consumer protection and reliability provisions in the bill. For instance, to avoid the "slamming" practices prevalent in telecommunications, the law requires confirmation (in writing or from a third party) that a customer has indeed chosen to switch power suppliers. AB 1890 also requires the CPUC to develop terms, conditions, and guidelines for power marketer and aggregator certification and registration.
Unfortunately (or perhaps fortuitously), on August 10, just after a Saturday committee session had adjourned, the lights went out in California when the entire western power grid collapsed. This power outage (and an earlier intertie problem), along with problems at PG&E over storm response, raised additional concerns over the interaction of deregulation and reliability. As a result, the conference committee called for creation of an oversight board (made up of political appointees) to oversee the governing boards of both the ISO and the Power Exchange. In addition, AB 1890 includes language that expresses the Legislature's desire that all utilities in the western states must enter into a compact with California's utilities regarding reliability and notification standards.
As with all legislation, AB 1890 is full of gray areas open to conflicting interpretations. For example, certain parties have construed some of the language on CTC exemptions to broaden what may have been intended. Undoubtedly, the next legislative session will see the introduction of various "clean up" bills. Among the most unhappy groups are the power marketers, who participated little in the development of the bill and whose interests were not put forward aggressively. The combination of utility stranded-cost recovery and limited exemptions from CTC has narrowed opportunities for the marketers. At this time, municipal utilities are also assessing, or perhaps re-assessing their share of benefits under the new law.
Nevertheless, the California legislation sets the state on a course toward a competitive electric power market. Much remains to be done, but the state's commitment to restructuring is now embedded in public policy. t
Dan Richard is principal and Melissa Lavinson an associate with Morse, Richard, Weisenmiller & Associates, Inc., an economic and business consulting firm headquartered in Oakland, CA.
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