1998 Restructuring Activities by State


A federal judge in Montgomery Ala. Dismissed a suit brought by marketers and industrial users against a controversial 1996 Alabama law, which allows utilities to claim stranded-cost recovery if retail users switch to a new supplier. The July 29, 1998 ruling did not settle the basic legal issues involved, finding only that the plaintiffs did not have "standing" to bring the suit because no stranded costs were awarded by state regulators.

The law enacted in May 1996 gives the Alabama Public Service Commission and state courts the right to review new retail power sales contracts and set stranded cost charges if called for.

Energy marketer American Energy Solutions and industrial user group, Alabama Electricity Consumers Coalition (AECC) brought the suit in March 1997. Even though no claims for stranded costs have been filed, the plaintiffs claimed the threat of such costs chilled their ability to enter competitive power deals, costing users substantial savings on power costs. They said this violated the Commerce Clause of the U.S. Constitution and various federal and state laws.

But in the order (Civil Action No. 97-D-96-N) the judge said that since no actual stranded costs had been imposed no injury had occurred and the plaintiffs did not have standing to bring the case.

The Alabama law is unusual because the state has not enacted any legislation to restructure the electric industry. Also the suit was one of the first raising such Commerce Clause claims against a state stranded cost rule.

Currently, the Alabama Public Service Commission is beginning a review of retail competition issues. But this is mainly as a protective action in case the state is forced to restructure under federal law and no target date has been set for a decision to introduce choice.


Due to its geographical location, the Alaska Commission was not contacted.

Arizona - NEW

The five largest sellers of electricity in Arizona asked the Federal Energy Regulatory Commission to approve formation of a voluntary, non-profit Arizona independent system administrator (ISA) (Docket ER99-388-000).

An ISA is needed in Arizona to handle operation of the state”Ēs transmission facilities in a competitive retail power market, scheduled to open in phases starting January 1, 1999, officials at Tucson Electric Power (TEP) said.

Salt River Project, Citizens Utilities and Arizona Electric Power Cooperative join Arizona Public Service and TEP in the FERC request.

The five companies expect an Arizona ISA to only be temporary and eventually merged into the multi-southwestern state Desert Star independent system operator. But right now "its obvious that an ISO would not be operational in the time frame needed for implementation" of a competition plan in Arizona, TEP officials said.

An ISA is not in conflict with detail of the recently completed electricity competition settlement between Arizona Public Service, TEP and the Arizona Corporation Commission (ACC) staff, TEP said.

That agreement – now pending before the ACC – calls for TEP to take over the transmission facilities of APS in exchange for a portion of TEP”Ēs generating assets. TEP, APS and the ACC each said they favor one company operating all of Arizona”Ēs transmission assets, although the settlement agreement covers only the facilities of the IOUs and no deal is yet in motion for TEP acquisition of facilities operated by state-owned Salt River Project.

The five companies asked FERC to approve the project for operation by January 1, 1999.

Start-up costs are put at $1.475-million and annual operating costs at $1.65-million. APS, TEP and Salt River Project will carry most of the start-up and operating costs.

TEP emphasized the ISA is needed, even in the ACC does not approve the settlement agreement in time for the January 1 start of competition.

Currently, the ACC procedure for the settlement involves testimony until early-December. APS and TEP asked the ACC for a more rapid consideration of the agreement, but intervening parties opposed to the settlement managed to slow the process.

The slower pace of consideration raises the possibility the settlement could be modified substantially. On January 1, 1999, newly elected Republican Tony West replaces current ACC member Democrat Renz Jennings, a strong advocate of competition.

West is more ambivalent about his position on competition and is a close ally of sitting ACC member Carl Kunasek, who November 20 publicly expressed his opposition to the current competition plan.

If an ACC vote is not taken before January 1, 1999, it will be West not Jennings that casts the key vote. The other ACC member, Jim Irvin, supports competition.


An electricity competition settlement between Arizona”Ēs two largest investor-owned electric utilities and the Corporation Commission staff allows for full stranded cost recovery, modest price cuts and auction of 1,992 MW of generation. Arizona Public Service and Tucson Electric Power signed separate agreements with staff. Each has different details, but both call for opening the power market January 1, 1999 for large consumers with demand above 1 MW, others with demand above 40-kW and 0.5% of residentials.

Afterwards, 0.5% of residentials will be offered an EPS option until January 1, 2001, when the entire APS and TEP market opens to full competition.

The settlements differ on stranded cost recovery, transmission, asset divestiture and electricity price cuts (Docket No. 00000C-94-0165). Under a formula in the agreement, APS would reduce power prices for customers selecting the company as the ESP by "at least 4%" in 1999-2002. Customers choosing to purchase generation from other providers will receive a credit from APS related to the actual market price of generation.

The APS settlement allows for recovery of about $533-million in stranded costs through a six-year market generation credit (MGC) extending to June 30, 2004, after which any uncollected stranded costs would be absorbed by the company.

Customers opting for service from a competitor would be billed for transmission, distribution and related billing, metering and ancillary services at the company”Ēs then-current stranded offer bundled rate for service less a MGC. The only difference between the "non-generation" rate and the company”Ēs current rate is the MGC. The APS methodology allows for stranded cost recovery equal to the difference between the approved generation costs in the bundled standard offer rate and the MGC.

APS will also establish separate corporation affiliates for generation, distribution and ESP services by year-end 2002. Existing APS transmission assets – about 2,200-mile with a current book value of $162-million – will be transferred to TEP in a cashless swap for certain TEP generating assets. APS will exchange transmission facilities of 345-kV and higher for TEP”Ēs equity interest in the 1,570 MW Four Corners plant and the 2,240 MW Navajo generating plant. Once the exchange is complete, TEP will execute a four-year power sales contract with APS to purchase 200 MW of output from the exchanged units.

If the swap is approved by the ACC, TEP”Ēs transmission company affiliate will become the sole builder and owner of transmission assets in the state offering open access to all companies.

The agreement TEP signed is different because TEP opted to 100% stranded cost recovery by agreeing to divest all generation. TEP owns or leases 1,895 MW of capacity at five fossil fuel plants. TEP will divest its generation, pursuant to specified auction protocols, by December 31, 2000. The ACC must sanction the new buyers, as must the Nuclear Regulatory Commission and the FERC, among others.

TEP”Ēs stranded costs will be calculated to include the difference between the book value of generation assets under traditional regulation and their market value determined through the auction process. TEP estimated stranded costs may range between $475-million and $1.1-billion. Under its proposal, TEP would recover stranded costs and a return on any unamortized balance over 10-years through an Interim Transition Charge, from January 1, 1999 through December 31, 2000 and a Competition Transition Charge from January 1, 2001 through December 31, 2008.

In addition, TEP said it needs additional financing to make up for the company”Ēs leases and other obligations related to the generation. To obtain that financing the settlement includes imposition of a "competitive transition charge" on rates and suggested securitization of the revenue stream derived from the charge by issuing bonds through a special purpose entity. If the ACC approves the securitization, it would be the first administrative – that is not legislated – securitization of stranded costs in the U. S.

TEP retail electricity customers would receive a 1% price cut on July 1, 1999 and July 1, 2000. After December 31, 2000, retail prices will be determined in part by the price TEP has to pay to acquire power in the competitive generation market.


Entergy Arkansas says state lawmakers should require the Arkansas Public Service Commission to allow utilities full stranded cost recovery in any new restructuring law. Entergy warned that if utilities received only partial recovery, the state could expect legal delays, which would threaten the January 1, 2002 target, set by the PSC for starting retail competition.

In comments filed to the PSC September 11, 1998, Entergy also said the PSC”Ēs plan to complete regulatory proceedings and start choice by Jan. 1, 2002 was too optimistic (Doc. No. 97-451-U). It said the legislature should instead order that deregulation occur no earlier than Jan. 1 2002 and no later than Jan. 1, 2004. This would give the PSC the flexibility to move ahead with competition when it believed it was ready.

The PSC released its draft recommendations on restructuring August 28, 1998 saying it would seek broad legislative authorities to determine policy on several key areas. After reviewing comments, the PSC will file final recommendations to the legislature October 1, 1998.

In its draft, the PSC said it was wary of allowing full stranded cost recovery, which would lessen the benefits of competition in the state. But it believed some recovery would be needed to maintain utility financial integrity. It asked for wide powers to determine costs and recovery levels.

In its comments, Entergy said any deregulation law passed by the General Assembly should endorse a policy that would result in full recovery of prudently incurred, non-mitigatable stranded costs. " It added that determining costs would also be hotly contested, and said that lawmakers should give clear guidance on that issue.

Entergy also said the legislature should restrict PSC authority to establish new market structures and especially bar it from ordering divestiture of generation, except in cases where a court convicts a utility of market abuses.

Entergy also questioned the PSC plan to bid default service out to independent providers as a means of reducing utility market power, saying it was premature to make that decision at this time.

In other comments, both industrial groups Arkansas Electric Energy Consumers and marketer Enron Energy Services said that based on the PSC”Ēs own hearing schedule, it would be feasible to start retail choice by Jan. 1, 2001. AEEC said that delaying a year until 2002 would cost users about $200-million in lost savings.

The PSC staff continued to support the compromise Jan. 1, 2002 date and said the legislature should provide very specific guidance in any provisions to securitize stranded costs, covering especially the extent of state guarantee.


The Arkansas Public Service Commission has issued a draft report on restructuring which recommends retail competition for generation to begin in the state "no later than January 1, 2002." The report issued August 28, 1998 (Docket No. 97-451-U et al.) Called on the state legislature to act during its 1999 session to mandate restructuring and give the PSC several specific powers to set new market structures, control market power and provide for stranded cost recovery.

The PSC also commented on the disruptions in energy markets in the Midwest during June and July, saying those events should not be a reason to delay competition in Arkansas. The PSC asked interested parties to file comments on the draft report by Sept. 11. It will submit a final version of the report to the legislature by October 1, 1998.

The PSC opened an investigation of deregulation issues in December 1997 and during hearings last May industrial users proposed a 2000 start date for choice while Entergy Arkansas favored 2004, but said starting competition in 2002 would be feasible under certain circumstances.

In choosing the 2002 date, the PSC seemed to be mainly worried about timing issues, saying it would need 18 months to two years after the legislature acts to hold hearings and issue rules to begin choice.

In its report the commission said industrial users would benefit at once from retail choice but smaller residential users might not see rate cuts until later and might even face temporary increases. The commission believes that restructuring would bring benefits to all customers over the long term, but said it was too early to quantify likely cost savings. It said benefits would come through a combination of lower generation costs, better allocation of generation resources in the state and region and an improved array of service offerings.

At the same time, the PSC cited movement towards restructuring in Oklahoma, Texas, Louisiana, Mississippi and Missouri. It said that if Arkansas maintained the status quo it would be a clear economic disadvantage once other states offered competitive power.

On market power issues, the PSC said it should have authority to order several remedies including functional unbundling, use of an independent system operator, use of an independent transmission company as proposed by Entergy and asset divestiture.

The commission said it was not clear that post-restructuring market power problems would be sever enough to require divestiture and that in any case it was uncertain if the large nuclear plants in Arkansas could be sold at this time. At the same time it said functional unbundling and a code of conduct might not be enough to protect against abuses.

The commission took no clear position on use of an ISO or an independent transmission company. It doubted an Arkansas-only ISO would be practical and said Entergy”Ēs proposal had several drawbacks including whether the new company would be truly independent from Entergy corporate interests.

The PSC said no action was needed at this time on market structures such as poolcos, power exchanges and use of bilateral contracts. Instead these should be left to "spontaneous development in the private sector."

In asking for powers to set stranded cost charges, the PSC took a moderate position between customer and utility claims. It noted such costs would be hard to quantify and would slow the benefits from decontrol for customers. But it also said, "some amount of recovery will likely be necessary to maintain utilities”Ē financial integrity."

The commission also asked for authority to allow securitization of stranded costs "if appropriate." But said it was wary of locking in stranded costs, which were actually higher than necessary. It also said that the state should be careful in the way it sets up the securitization and should not become a "guarantor" of the securities.

The PSC asked for authority to develop criteria for generation suppliers, codes of conduct to protect retail users and a bidding process for default suppliers.

The PSC agreed that municipal utilities should have an option to allow retail choice or not. But said once a municipality elects to enter the competitive arena it should not be allowed to exit the market at a later date.

The commission said the legislature should also review the tax impacts of restructuring but made no specific proposals and also opposed adoption of a rule requiring reciprocity with other states on power sales.

California - NEW

California voters soundly defeated Proposition 9 that would have overturned key portions of the state”Ēs electric restructuring law and prohibited investor-owned utilities from recovering stranded investments in nuclear power plants.


All suppliers in the California Independent System Operator system will be allowed market-based rates for ancillary services in hopes of adding more suppliers and creating more competition, the Federal Energy Regulatory Commission said.

To mitigate against any that might have market power in particular services, however, the FERC said it will allow the ISO to continue to impose price caps until it overhauls the flawed market next year (Docket No. ER98-2843, et al.).

Some may call FERC”Ēs decision to allow the ISO to impose caps just as the California utility industry is opening up to free-market forces a step backward, Commissioner William Massey said, but he explained FERC sees structural problems that need to be fixed, and the short-term caps will allow "breathing room for long-term solutions."

When prices in the California ancillary services market spiked this summer to as high as the computer could register, they did not self-correct as those in the Midwest late-June market did, said Massey, so short-term intervention was called for to ferret out the root of the problem. FERC originally rejected the ISO”Ēs plea for price caps, then endorsed the caps after the ISO imposed them as an emergency measure. The commission, however, refused to revoke market-based ancillary services pricing authority for the few firms that had then been granted such rates.

The commission also asked independent monitoring groups in the state to investigate the spikes, and they found a flawed design that does not promote vigorous competition. They recommended allowing the price caps on an interim basis until structural problems could be corrected. One of the problems with the market is that a few suppliers can receive market-based rates for ancillary services while others are subject to cost-based rate caps. Those with caps have no incentive to bring additional supply to the ancillary services market during periods of high demand as they can earn more diverting all of their supply to the market-based energy market. This creates a shortage in the ancillary services market and drives prices higher.

To remedy the problem, FECR asked that all ancillary service providers that have rate schedules on file to sell energy at market-based rates to the ISO amend them to include ancillary services within 15 days. In separate orders, the commission approved San Diego Gas & Electric and Sempra Energy Trading requests for market-based pricing of ancillary services, but it denied a request for market-based rates for ancillary services outside the California ISO.

In order to keep those suppliers that could have more than 20% market share in some areas, such as Pacific Gas & Electric in northern California, FERC will maintain the temporary price caps. FERC told the ISO to submit a comprehensive market redesign proposal by March 1999.


Green marketers are perpetrating a huge hoax on California consumers by claiming to be expanding the supply of green power while predominantly reselling renewable energy resources that are already being paid for by utility ratepayers, according to a report from Washington, D.C.-based advocacy group Public Citizen.

Renewable energy backers charged that the report was an attempt to sabotage the fledgling green power market in California before it has a chance to develop in order to influence Washington lawmakers in framing federal electric restructuring legislation.

The report, Green Buyers Beware: A Critical Review of "Green Electricity" Products, which was conducted through Public Citizen”Ēs Critical Mass Energy Project division, contends that the flurry of green marketing unleashed by California”Ēs new retail electric market will not increase renewable energy production, diversify the electric system resource mix, or decrease air pollution.

That”Ēs because most of the green power being sold in California comes from renewable resources that are controlled by utilities, often through long-term power purchase contracts. Indeed only one small green marketer – San Jose-based "cleen ”Ęn green energy " - in purchasing green power solely from renewable energy producers that are not owned or under contract to a utility. The report found "cleen ”Ęn green" purchases its power through the APX Green Electricity Exchange, which only deals in non-utility owned resources.

Renewable energy advocates blasted the report as a "rush to judgment" and "hit piece" that condemns the fledgling green power market just six months after the launch or retail competition in California. Three national environmental groups – the Sierra Club, Environmental Defense Fund and Natural Resources Defense Council – issued a joint "dear colleague" letter critiquing the study as misguided and unfair.

Meanwhile large industrial, commercial and institutional customers are helping fuel the demand for new renewables by purchasing green power at a premium. For example, Patagonia signed a contract with Enron Wind that will result in construction of new wind turbines; Toyota Sales U.S.A. switched its 12-MW load to Edison Source; Air Touch Cellular is buying green power from the Sacramento Municipal Utility District; and San Monica became the first city in the nation to decide to switch its entire electric load to renewables.


The California Legislature has enacted several pieces of legislation intended to strip the California Public Utilities Commission of its autonomy and regulatory authority over the state”Ēs new competitive electric market.

Senate Bill 779, which was signed into law September 30, 1998, will make PUC decisions after January 1, 1999 subject to judicial review by the state”Ēs appellate courts. Until now, the only avenue for challenging PUC decisions was the California Supreme Court, which rarely heard such appeals unless significant legal issues were involved. The bill also establishes a number of administrative and procedural reforms of the commission.

PUC President Richard Bilas predicted that utilities and other parties would take advantage of the new law to challenge most major PUC decisions, prolonging the regulatory process but spurring the commission to make better decisions. However, Bilas expressed concern that California stakeholders might follow the example of Illinois, where virtually every regulatory decision is challenged in the courts, hamstringing the agency from acting.

In a further swipe at the PUC”Ēs authority, the legislature adopted language in the 1999 state budget expanding the authority of the state Electricity Oversight Board over California”Ēs new electricity market and doubling its staff and funding.

The legislature moved to curb intervention by the PUC at the FERC by designating the Oversight Board as the lead agency to represent California on issues related to the California Power Exchange, the Independent System Operator, reliability of the electric grid, generation and bulk power markets.

The Oversight Board, PUC and California Energy Commission are currently drafting a Memo of Understanding to clarify their different roles and jurisdictions and limit filings by state agencies at FERC. As the lead agency, the Oversight Board will be able to draw upon staff, resources and expertise from both the PUC and the energy commission.

The MOU, which is expected to be adopted by the end of the year, specifies the areas over which the PUC exercises regulatory authority, including electric distribution, utility affiliate rules, gas supply and fuel issues. By contrast, market issues and reliability, as well as, ISO and PX matters, are explicitly the province of the Oversight Board.

The budget language and MOU process have already borne fruit inducing better cooperation between the various state regulatory agencies. "We do seem to be working well with the ISO and Oversight Board and have coordinated some of our recent filings together on a going forward basis," said Jim Hendry, an energy advisor.

Meanwhile the Oversight Board has filed an appeal in federal court of a FERC order last year that would sharply curb its authority over the PX and ISO by prohibiting that state agency from appointing members of the ISO and PX governing boards and exercising appellate power over their decisions.

Both the ISO and PX have asked FERC and the Oversight Board for authority to expand their abilities and powers. For example, the ISO is seeking approval from the state for transmission system upgrades and may seek eminent domain authority. However, the state would withhold that authority from the ISO if it had no jurisdiction over its operations.

Chipping away further at the PUC”Ēs authority, the legislature passed another bill, SB1602, prohibiting the PUC from undertaking restructuring of the core natural gas industry before January 2000, short-circuiting a procedure on which the commission was set to embark.

Peace and other state lawmakers sought to reign in the PUC to prevent the commission from initiating gas restructuring too far ahead of the legislature as it did with electric restructuring.

"The PUC was moving faster than the legislature," as it had dome with electric restructuring, said John Rozsa, Senate energy advisor. "Electric restructuring was foisted on the legislature. They didn”Ēt want them doing it with gas." Unlike the PUC regulatory arena, the legislative process is more public and entails more negotiating between parties, requiring more time", he said.


Colorado lawmakers suspended action on three measures designed to deregulate the state”Ēs electric power industry and opted to study the issue for another year. Lawmakers formed a task force and will study the issue until the 1999 session.


June 15, 1998: Commissioners and staff of the Department of Public Utility Control held a technical meeting to kick off regulatory efforts to bring electric power competition to Connecticut. At the meeting the DPUC unveiled its plan for accomplishing all of the tasks necessary to implement legis