Electric utilities in Florida are required to provide safe, adequate, and reliable electric service to the public at the lowest possible cost. Historically, electric utilities have been responsible for the production, transmission, and distribution of electricity, as well as the metering and billing of the electric energy sold to homes and businesses. This complete package of electric services has been termed "bundled retail service" or "integrated utility service," and, for the most part, customers purchase electricity at a fixed price for all these services.
In Florida, a total of 54 electric utilities currently provide bundled retail service to end-use customers in their service areas. The Florida Public Service Commission (FPSC) fully regulates the rates and services of five investor-owned utilities. They are Florida Power & Light Company (FPL), Florida Power Corporation (FPC), Florida Public Utilities Company (FPUC), Gulf Power Company (Gulf), and Tampa Electric Company (TECO). Together, these five investor-owned utilities provide approximately 79 percent of all electricity sold to retail customers in Florida. The remaining 21 percent is provided by 33 municipal electric utilities and 16 rural electric cooperatives. The rates charged by municipal electric utilities are set by local governments, while the rates of rural electric cooperatives are set by the Board of Directors acting on behalf of its members. However, the FPSC does have rate structure jurisdiction for municipal and cooperative electric utilities. Rate structure simply means that the rates set by municipals and rural electric cooperatives must be fairly divided among the customer classes (i.e., residential, commercial, industrial, etc.). The FPSC also has jurisdiction over all electric utilities in the areas of public safety, territorial boundaries, major power plant and transmission line need determinations, conservation, cogeneration, and power supply planning.
In Florida, not all electric utilities generate all the electricity they sell to their retail customers. Many smaller municipal electric utilities, the rural electric cooperatives, and one small investor-owned utility in Florida purchase all or part of their customers' generation requirements from other utilities. They also purchase the transmission services necessary to move their purchased power from the power plants where the electricity is generated to the load centers where their retail customers reside. These partial requirements and full requirements purchases of generation and transmission services are one element of the wholesale market for electricity which has existed in Florida and the rest of the nation for some time.
The other element of the wholesale market is the interchange market. In the interchange market, utilities which would otherwise own and operate all their own generation may find it economical to purchase capacity and energy from generating units owned by other utilities. Purchases in the interchange market can take place on an hour-by-hour basis, on a short-term basis up to a year, or on a long-term basis for many years. The price, terms, and conditions associated with interchange purchases are either negotiated by the purchasing and selling utilities or determined by a formula tariff approved by the Federal Energy Regulatory Commission (FERC). Historically, the FPSC has encouraged generating utilities to pursue cost-effective purchased power alternatives. The revenues generated for the selling utility and the savings realized by the purchasing utility from these wholesale transactions flow back to the utility's retail customers through a cost recovery clause, resulting in reduced electric bills.
The FERC regulates the rates, terms, and conditions of wholesale energy sales and the transmission services necessary to accomplish these sales. In the past, there has been a bright line between the FERC's jurisdiction over wholesale sales and wholesale transmission and the States' jurisdiction over retail sales and retail transmission. Recently, however, certain Federal legislation and actions by the FERC have clouded the distinction between this Federal and State jurisdiction. This growing overlap between State and Federal jurisdiction will be discussed within this report.
In the early years of its development, the electric industry was composed of individual electric utilities that served isolated industrial customers and local community lighting loads. Low voltage transmission was used to access individual industrial customers and community load centers. Utilities were not interconnected with each other, and each had to provide their own generating resources necessary to serve their customers. As advances were made in the development and operation of high voltage transmission technology, more and more utility systems found it advantageous to interconnect their systems.
At first, utilities interconnected to increase reliability. With transmission interconnections, utilities were able to rely on emergency generating assistance from neighboring utilities during major generating unit outages. Because of the enhanced reliability gained by these mutual assistance agreements, the need to maintain surplus reserve generating capacity for each utility was reduced. This reduced each utility's costs of providing reliable service. From these early beginnings, competition in the wholesale supply of generation emerged.
Wholesale Market in Florida
Prior to 1980, peninsular Florida had limited transmission interconnections to the rest of the nation. At that time, the interconnections consisted of a few 230,000 volt and 138,000 volt transmission interties at the Florida/Georgia boundary. Together, peninsular Florida utilities could import a maximum of 400 MW of generation. In essence, peninsular Florida was an electrical island. Because of these weak interstate interties, the wholesale market in Florida consisted primarily of partial requirements and full requirements supply arrangements between peninsular Florida generating and non-generating utilities and, to a lesser degree, purchased power interchanges between peninsular Florida generating utilities
During the oil embargo of the 1970's, Florida's utilities were especially hard hit. Oil was the dominant fuel for electric power generation. As prices soared at the gas pump, so did customers' electric bills. Also, peninsular Florida utilities experienced several bulk power interruptions resulting in rotating customer blackouts. These interruptions were caused when recently constructed nuclear units in the state experienced forced outages. Because of their large size, an unplanned outage of one of these nuclear units would cause significant degradation in the quality of the power supplied by the state's bulk power grid (voltage and frequency decline). These declines in frequency would cause the weak tielines between peninsular Florida and the Southern Company to open, thereby aggravating the problem and increasing the magnitude of customer blackouts. In response to these concerns, the FPSC worked with the peninsular Florida utilities to investigate the feasibility and cost-effectiveness of strengthening the transmission interties between peninsular Florida and the Southern Company. As a result, certain peninsular Florida utilities decided to construct two 500,000 volt transmission lines interconnecting peninsular Florida with the Southern Company. These lines increased the maximum transmission import capability into peninsular Florida to its present level of 3600 MW. The FPSC allowed special cost recovery treatment for the construction of these lines.
With the increased ability to import generation into Florida, peninsular Florida utilities entered into purchased power contracts for "coal-by-wire" from the Southern Company. Both the Florida utilities and the utilities comprising the Southern Company benefited from these contracts. The members of the Southern Company were able to more efficiently utilize their existing coal-fired generation. Peninsular Florida's ratepayers enjoyed increased reliability and lower fuel costs.
Another FPSC action which has facilitated the development of the wholesale market in Florida was the creation of the Florida Energy Broker. The Energy Broker was developed to facilitate short-term economy sales between the state's electric utilities. The Energy Broker is a computerized system for marketing hourly non-firm electric energy. Every hour, the Energy Broker matches potential sellers and buyers and results in a benefit to the ratepayers of both utilities. To encourage use of the Energy Broker, an incentive mechanism was created by the FPSC for investor-owned utilities, in which they were allowed to retain 20 percent of the profit made on Energy Broker sales. In 1995, the Energy Broker allowed membership by entities other than traditional Florida utilities, including certain non-utility generators, known as Exempt Wholesale Generators, and power marketers. Since the inception of the Florida Energy Broker in 1978, total savings in energy cost have exceeded $750 million.
While the Energy Broker became an important catalyst in the development of the wholesale market in Florida, today most wholesale sales are made outside the Energy Broker system. Currently, wholesale sales in Florida run the gamut from short-term non-firm sales to long-term firm contracts lasting several years. Most economy transactions have migrated from the Energy Broker system to more flexible separately negotiated contracts. However, wholesale sales in Florida continue to be a relatively small portion of investor-owned utilities' sales and are predominantly conducted between Florida's utilities. The table below displays the percentage of 1998 operating revenues by type of wholesale sale for each of the three major peninsular Florida investor-owned utilities. As shown, the percentage of operating revenues derived from wholesale transactions is small relative to total revenues, with the bulk of wholesale revenue derived from full requirements, long-term wholesale sales.
Federal Legislation - Public Utilities Regulatory Policy Act
Many industry analysts attribute the beginning of increased wholesale competition to Congress' enactment of the Public Utilities Regulatory Policy Act of 1978 (PURPA). PURPA required electric utilities to purchase capacity and energy from qualifying cogeneration and small power production facilities, known as Qualifying Facilities (QFs). In implementing PURPA, the FERC required utilities to pay QFs their "full avoided cost," that is, the cost the utility would have incurred to construct the generation itself.
PURPA served as a catalyst to encourage the development of lower cost natural gas-fired generating technology. This new technology, known as a combined cycle unit, employs steam recovery boilers to recover waste heat exhausted from a conventional combustion turbine generating unit (similar to a jet engine) to produce additional electricity. Combined cycle units substantially increase fuel efficiency. They can be certified and constructed in a relatively short period of time at a fraction of the cost of building conventional fossil steam generation. These units also provide planning and operating flexibility because they can be constructed in a variety of modular sizes and operate over a wide range of load conditions. Combined cycle units also use less water and emit fewer air pollutants than other generation technologies. As a result of these technological gains in natural gas-fired generation and the current low cost of natural gas, the conventional view that generation is best provided by a regulated monopoly utility has been called into question.
Federal Legislation - Energy Policy Act of 1992
The Energy Policy Act of 1992 (EPACT) gave further impetus to wholesale competition in the electric industry by reducing the regulatory requirements for certain wholesale electric providers, known as Exempt Wholesale Generators (EWGs) or merchant plants. EWGs are entities that own or operate a generating facility strictly for wholesale energy sales. Prior to EPACT, any multi-state holding company entity which generated electric power was subject to the Public Utilities Holding Company Act of 1935 (PUHCA). This required filing with the Securities and Exchange Commission and various other regulatory requirements. These requirements made it difficult for affiliated entities of multi-state holding companies seeking to enter the generation market, as well as electric utilities seeking to create affiliate companies, to invest in and develop new sources of generation. EPACT encouraged the entry of new wholesale energy providers by exempting EWGs from the requirements of PUHCA. Also, EPACT authorized the FERC to allow certain EWGs to sell electricity in the wholesale marketplace at market prices, rather than the conventional cost-based rates required of monopoly electric utilities.
The rates charged by EWGs are generally set by the market. That is, if the FERC believes an EWG does not have excess market influence, the EWG can sell excess electricity at whatever price the market will bear. Unless specific contracts exist, load serving entities have the option, but are not required, to purchase electricity from EWGs.
EWGs/Merchant Plants in Florida
Hardee Power Station
The first EWG in Florida was the Hardee Power Station, a joint project between TECO Power Services, an affiliate of Tampa Electric Company (TECO), and Seminole Electric Cooperative. The unit is a 240 MW natural gas-fired combined cycle unit. The output of the unit is shared between TECO and Seminole for their respective retail customers' needs. The need for Hardee Power Station was approved by the FPSC on December 22, 1989 (Order No. 22335).Because TECO Power Services is an affiliate of TECO, a regulated investor-owned utility, the FERC initially decided that the rates charged for the plant's output should be cost-based. TECO petitioned FERC's ruling, contending that it does not have sufficient market power to adversely influence wholesale market rates in Florida. TECO has recently received the FERC's approval to charge market-based rates.
Duke New Smyrna
On March 4, 1999, the FPSC granted the determination of need for a 514 MW electrical power plant in Volusia County. The project, jointly requested by the Utilities Commission, City of New Smyrna Beach, and Duke Energy New Smyrna Beach Power Company Ltd., L.L.P. (Duke New Smyrna), was found to be needed and in the best interests of electric customers in Florida.
Based on the hearing record, 30 MWs from the project is needed by the City of New Smyrna Beach to partially replace 83 MWs of existing capacity contracts which will expire between September, 1999 and 2004. The price at which Duke New Smyrna has offered to sell the City these 30 MWs of replacement power is significantly less than what the City's retail customers are currently paying for purchased power. The City estimates that its energy costs will be reduced by $3.1 million per year net present value for the first ten years, and approximately $7.75 million total net present value for the following ten years, for a total estimated savings of approximately $39 million net present value. Also, the project will use approximately 2 million gallons of reclaimed waste water provided by the City that would otherwise be discharged into the Indian River. The low-cost power to be provided to the City is contingent upon the entire project being constructed. As such, if the project is not constructed, the City will have to construct or contract for higher cost capacity and energy.
The hearing record indicated that the availability and sale of the remaining 484 MW of capacity to other peninsular Florida utilities will enhance the reliability of the peninsular Florida electric grid and put downward pressure on wholesale power costs. Duke New Smyrna has elected to construct the 514 MW project as a merchant plant and received EWG status from the FERC. Other than the contract for 30 MWs to the City of New Smyrna Beach, Duke has decided to build the power plant without first entering into any long-term wholesale sales contracts with other Florida utilities. Duke asserts that the continued growth in electricity demand in Florida, coupled with the ability to economically displace high cost oil generation, will create market demand for the project's output. The direct risks associated with the construction of the project will be borne by Duke New Smyrna. No utility or its retail ratepayers will be obligated to purchase from the project. Rather, sales from the project will be made either on an as-needed, as-available basis or subject to negotiated contracts. As such, the Duke New Smyrna project presents another alternative for existing retail serving utilities, without putting Florida ratepayers at risk for the costs of the facility. Florida utilities will only purchase power from Duke New Smyrna if it proves to be the lowest cost alternative at the time a contract is entered.
In addition to these benefits to Florida's electric ratepayers, the hearing record indicated that the Duke New Smyrna Project will also provide other socio-economic benefits to the state. At a construction cost of approximately $160 million, the Duke New Smyrna Project will significantly add to the property tax base of Volusia County and other taxing districts. It is estimated that the project will provide $4.2 million annually to local taxing agencies. Peak employment during the construction of the project is expected to be 250 persons. Once construction is completed, approximately 20 permanent positions will be needed to operate the power plant with a total annual payroll of approximately $1 million.
The Commission's final order approving the need for the Duke New Smyrna project was issued on March 22, 1999. The major investor-owned utilities in peninsular Florida, FPL, FPC, and TECO, have appealed the Commission's decision to the Florida Supreme Court. These investor-owned utilities oppose the project because they contend that Duke New Smyrna should be required to enter into wholesale contracts with a retail-serving utility before construction of the power plant should be approved. They argue that EWGs such as Duke New Smyrna are not proper applicants for a determination of need by the FPSC. The investor-owned utilities also contend that only utilities with retail customers can (1) apply for a determination of need, or (2) sponsor the application for a determination of need by an EWG with which they have entered a long-term firm wholesale contract. The Florida Supreme Court is expected to hear oral arguments on the case by October, 1999 with a final decision expected by the end of the year. The final decision to approve the construction of the project has been postponed by the Governor and Cabinet, who make up the Power Plant Siting Board, until the Florida Supreme Court makes its ruling.
Constellation Power - Oleander Power Plant
Constellation Power, an unregulated subsidiary of Baltimore Gas and Electric Company, has announced its plans to construct a 950 MW natural gas-fired peaking power plant in Brevard County. The project will consist of five 190 MW gas turbines. The proposed plant will be an EWG merchant plant, selling capacity and energy through the wholesale electric market to Florida's utilities. Because the plant will consist of combustion turbines with no steam generation, it is not subject to the Power Plant Siting Act, and therefore is not required to obtain a determination of need from the FPSC. Applications have been filed for local environmental permitting. The project is currently being evaluated by the Florida Department of Environmental Protection for air and water permits. The anticipated in-service date of the plant is January, 2001.
El Paso Power Services Company
Florida Power Corporation (FPC) and El Paso Power Services Company (El Paso) have recently agreed to restructure certain existing cogeneration contracts. El Paso will acquire three existing contracts for the sale of capacity and energy to FPC. These three contracts were originally entered into in 1991 between FPC and Royster Phosphates, Inc. (Royster), Mulberry Energy Company (Mulberry), and CFR Bio-gen Corporation (CFR Bio-gen). In total, these contracts represent 184 MW of capacity and associated energy committed to be sold to FPC. Generation to supply these contracts is provided from two cogeneration facilities: (1) the natural gas-fired combined cycle Mulberry facility in Polk County, and (2) the natural gas-fired combined cycle Orange facility in Polk County.
Under the terms of the assignment, capacity payments made by FPC will be discounted for the remaining term of each contract, resulting in savings in excess of $100 million net present value. Associated energy savings are estimated to be approximately $15 million net present value. The agreement also provides that El Paso will waive its rights under PURPA to require FPC to purchase the capacity and energy from the two cogeneration facilities serving the contracts. El Paso will not be required to maintain the Mulberry and Orange units as QFs under PURPA. Rather, the Mulberry and Orange units will be operated as EWG merchant plants. FPC will continue to have first call on capacity and energy from El Paso up to the capacity commitments contained in the original contracts. However, when FPC is not using their full capacity commitment, El Paso is free to sell the energy from the Mulberry and Orange units on the wholesale market.
Reliant Energy (Reliant), a Texas based energy provider, has been pursuing the purchase of the Indian River Power Plant from the Orlando Utilities Commission (OUC). The Indian River Power Plant consists of three natural gas/oil-fired steam generating units which were originally built in 1960, 1964, and 1974. The total installed capacity of these three generating units is 608 MW. Initially, Reliant plans to sell capacity and energy from the units back to OUC. These sales to OUC would ramp down over a period of about four years. Capacity and energy not sold to OUC will be sold as EWG merchant capacity and energy on the wholesale market.
In a separate deal, Reliant has also been exploring the construction of a new EWG merchant peaking plant, named Reliant Energy Osceola, near Kissimmee, Florida. The proposed project would consist of approximately 460 MW of natural gas-fired combustion turbines with an in-service date of 2001. Reliant intends to sell approximately 300 MW to Seminole Electric Cooperative for an initial term of 5 years and 100 MW on the wholesale market. At the end of the proposed wholesale contract with Seminole, the full 460 MW capacity of the plant would be sold on the wholesale market.
Okeechobee Generating Company
Okeechobee Generating Company (Okeechobee), a wholly-owned subsidiary of California based Pacific Gas & Electric (PG&E), has recently filed an application for EWG status with the FERC. Okeechobee plans to construct a 500 MW class natural gas-fired, combined cycle power plant in Okeechobee County, Florida. The project will be interconnected with FPL's transmission facilities in the area and is expected to be placed in service in the Spring of 2003.
Merchant Plants in Other States
There are currently 10 states with fully operational merchant plants. These states include: California, Colorado, Connecticut, Massachusetts, Maine, New Mexico, New York, Texas, West Virginia and Wisconsin. Thirty-two additional states have merchant plants under various stages of development. Appendix A contains a map displaying the status of merchant plant development in each state.
A summary table showing the status of merchant plant capacity development in the United states, as of May 31, 1999, is given below. (1)
Over 80 percent of the 13,349 MW of U.S. installed merchant plant capacity is located in California. Most of these plants are not newly constructed plants, but existing plants that were previously owned by utilities and sold through divestiture. Appendix B contains further information on the location of these currently operational plants.
An additional 14,886 MW of merchant capacity is under construction or development. This includes 6,558 MW of capacity under construction in: Connecticut, Illinois, Massachusetts, Maine, Mississippi, Missouri, Nevada, Rhode Island and Texas. In addition, more than 8,000 MW of merchant capacity is under development. The plants characterized as under development have met or partially met the necessary siting requirements, and the completion of these projects is relatively certain. Appendix C provides further information on these plants.
There are also plans reported for 56,021 MW of additional merchant capacity. While these plants may have partially met the necessary siting requirements, completion is less certain than for plants under development. Appendix D contains further information on the location of these plants.
FERC Orders No. 888 & 889
Transmission is the bridge between electric generation and end-use customers. An efficient wholesale generation market cannot exist without an adequate and efficiently operated wholesale transmission system. Therefore, in addition to creating a new class of EWG merchant plants to foster competition in the wholesale generation of electricity, the Energy Policy Act of 1992 (EPACT) also addressed the FERC's authority to pursue open access for wholesale transmission.
In 1996, the FERC issued Orders No. 888 and 889 to establish rules governing a more open wholesale transmission market. Order No. 888 required all transmission-owning public utilities to make their transmission facilities available to any user at a fair price and in a non-discriminatory manner. In order to achieve these goals, Order No. 888 required all public utilities to "functionally unbundle" their wholesale power services. Functional unbundling entails requiring transmission owning utilities to: (1) take transmission services under the same tariff rates, terms, and conditions as do others; (2) state separate rates for wholesale generation, transmission, and ancillary services; and (3) rely on the same electronic information network that its transmission customers rely on to obtain information about its transmission system when buying or selling power.
Order No. 889 required that all public utilities establish or participate in an Open Access Same-Time Information System (OASIS). It also established standards of conduct designed to prevent employees of a public utility engaged in wholesale power marketing functions from obtaining preferential access to pertinent transmission system information. An OASIS is an Internet based transmission service reservation system where participating utilities can: (1) post information about transmission capacity available for purchase by transmission customers, (2) post information about the status of the transmission system, and (3) provide a means for transmission customers to request transmission service over defined transmission paths. Order No. 889 also established the type, frequency and format of the transmission-related information which must be posted on OASIS.
Finally, in order to extend the provisions of Orders No. 888 and 889 to all transmission-owning systems, FERC also required that non-FERC regulated utilities (e.g., municipal electric utilities and rural electric cooperatives) must adopt reciprocating and conforming transmission access policies before being able to take service under a FERC regulated public utility tariff.
Impact on Florida
Order No. 888 has blurred the jurisdictional lines between state and federal regulation of wholesale and retail transmission. Prior to FERC Order No. 888, there was a clearer line of demarcation between state and federal jurisdiction. Under the Federal Power Act (FPA), the FERC was authorized to regulate the rates, terms, and conditions of wholesale energy sales and transmission in interstate commerce. In defining the FERC's jurisdiction over wholesale transmission, the FPA was careful not to usurp existing state jurisdiction over retail transmission service. Section 212 of the FPA states:
(g) Prohibition On Orders Inconsistent With Retail Marketing Areas. -- No order may be issued under this Act which is inconsistent with any state law which governs the retail marketing areas of electric utilities.
This section of the FPA enunciates the Congressional intent to preserve the status quo with regard to federal and state jurisdictions over retail services. In Order No. 888, however, the FERC extended its jurisdiction into several areas that have historically been the province of the states.<
One area in which the FERC has asserted jurisdiction is the regulation of unbundled retail transmission when a state orders retail access. Unbundling means the separation of the rates, terms, and conditions for generation, transmission, distribution, and other retail services provided by an electric utility on customer bills. If a state decides to allow retail competition, unbundling is a prerequisite. The FERC contends that if a state requires its electric utilities to provide retail competition for generation services, the state will relinquish its ratemaking authority over the transmission component of the unbundled rate. The FERC has also asserted jurisdiction over the recovery of costs, if any, stranded by state-directed or voluntary retail wheeling when a state commission lacks authority to address the issue or when a retail customer converts to a wholesale customer (municipalization).
While the FERC has expressed its intent to provide deference to the states on issues pertaining to stranded cost recovery and the transition from bundled to unbundled rates, it is not clear what voice state regulators will truly have at the FERC. Further, in states such as Florida where the Legislature has established a clear and pervasive state regulatory scheme, it makes little sense for the FERC to preempt the state's jurisdiction. Costs for facilities that are currently under the jurisdiction of state authorities do not suddenly become the FERC's jurisdiction because retail wheeling is instituted. Transmission lines still perform the same function of bringing power to the retail customer located within the territory of a state regulated utility. The states are in a much better position to judge the extent and value of assets which may become stranded as a result of retail wheeling. In most cases, the states have approved both the construction and the cost recovery for these facilities under bundled rate structures. In light of these concerns, on April 11, 1997, the FPSC filed a petition in the United states Court of Appeals challenging these elements of Order No. 888. The FPSC was joined in this appeal by the state commissions of New York, Arkansas, Idaho, North Carolina, Wyoming, Illinois, and Washington and the National Association of Regulatory Utility Commissioners (NARUC). Briefs have been filed in the case but the U.S. Court of Appeals has not yet acted.
Regional Transmission Organizations
On May 13, 1999, the FERC issued a Notice of Proposed Rulemaking (NOPR) proposing to amend its regulations under the Federal Power Act (FPA) to facilitate the formation of Regional Transmission Organizations (RTOs). Perhaps because the FERC has not seen all the changes it envisioned from Order No. 888, it has begun looking into establishing RTOs as the next step toward ensuring fair and non-discriminatory access to transmission services and ancillary services for all users of the transmission system.
An RTO would perform all the functions currently performed by individual transmission owning utilities. The difference would be that an RTO would plan, construct, maintain, and operate all the transmission facilities within a entire region. As such, an RTO, rather than the current transmission owners, would exercise independent control over the development and operation of the transmission system. The transmission owners would receive compensation for their existing transmission investments based on the usage of their transmission lines. FERC looks at the formation of RTO's as a way to mitigate vertical market power associated with generators controlling access to the transmission system.
At the moment, the FERC's authority to mandate RTO's is not clear. Nevertheless, the FERC has proposed rulemaking to adopt certain minimum characteristics and functions for a transmission entity to qualify as an RTO. FERC's proposed characteristics of an RTO, as outlined in the FERC NOPR, are provided in Appendix E. The transmission organizations which have been approved by FERC are contained in Appendix F.
On July 30, 1999, the FPSC submitted comments on the FERC's proposed rules concerning RTOs. The FPSC has encouraged the FERC to continue to maintain a flexible policy toward the formation of RTOs. The FPSC believes that the FERC lacks the authority to mandate a one-size-fits-all solution and must proceed on a case-by-case basis to address specific transmission problems. This can best be accomplished by working with the states to develop regional approaches that achieve regional market consensus and are endorsed by state regulators.
Florida Transmission Issues
In Florida, the FPSC has broad authority under Sections 366.04(2)(c), and 366.05(8), Florida Statutes, over transmission grid-related matters (the Grid Bill). The FPSC is vested with jurisdiction over the planning, development, and maintenance of a coordinated electric grid throughout Florida. This jurisdiction includes establishing the provision for sharing of energy reserves of all electric utilities in the state for the establishment of conservation and reliability within a coordinated grid. To the extent that a deficiency is determined to exist in the Florida grid, the FPSC is authorized, after appropriate evidentiary proceedings, to order utilities to correct deficiencies and to allocate the costs of such improvements on the basis of benefits received.
In the enforcement of these responsibilities, each electric utility in Florida is required pursuant to Chapter 186, Florida Statutes, to file Ten Year Site Plans annually with the FPSC. These plans identify the utilities' forecasts of system load, demand-side conservation achievements, and plans for generation and transmission additions required to serve the electrical requirements of Florida's customers. These plans are reviewed by the Commission and a report of their suitability from a planning perspective is provided to the Florida Legislature. Ultimately, as a utility's plans come to fruition with the construction of additional bulk power facilities, the FPSC must determine and approve the need for major new generation and transmission facility additions pursuant to the Florida Electrical Power Plant Siting and Transmission Line Siting Acts. Under the Grid Bill, the FPSC also has the authority to initiate a need determination on its own motion. The need determination process is followed by environmental and land use review by the appropriate other Florida agencies. Finally, site certification is approved, or denied, by the Governor and Cabinet sitting as the Siting Board. The FPSC has a considerable history of oversight activities in its implementation of the Grid Bill and the Electrical Power Plant and Transmission Line Siting Acts, which have resulted in significant increased efficiency of Florida's electric grid and savings that have benefitted the state's electric consumers.
Pursuant to the FPSC's jurisdiction over grid related matters, work continues in Florida to explore Florida-specific transmission issues. The FPSC has held a series of public workshops in 1999, to solicit views of the Florida electric utilities and other interested parties regarding RTO formation. Three proposals have emerged from these workshops: (1) Independent Transmission Administrator (ITA) Proposal, (2) Regional Transmission Solution (RTS) Proposal, and (3) Public Not-for-Profit Transco Proposal. These proposals are summarized below.
The ITA proposal was developed and submitted by the following entities:
The ITA would not own or profit from any generation, transmission, or distribution facilities and would not engage in the purchase or sale of electric energy or capacity. The business affairs of the ITA would be governed by a "stakeholder" Board of Directors with fifteen members representing investor-owned utilities, municipal utilities, cooperative utilities, power marketers and independent power producers. Each of the voting members of the Board of Directors would be given one vote, and any action would require approval of a 2/3 majority of voting Board Members.
The proposal put forward by Florida Power and Light Company and Florida Power Corporation, the RTS Proposal, is not an RTO proposal. Their proposal would not require FERC approval. At this point in time, only FPL and FPC support this proposal.
The RTS proposal relies on the FPSC to provide independent oversight and governance over transmission planning and operations. The FPSC would resolve disputes with respect to the need for new transmission facilities or new interconnections. Under the proposal, an FPSC Security Coordinator Representative would be hired by the FPSC, and located on a permanent basis at the Control Center that performs the Security Coordinator function. The Security Coordinator Representative would be responsible for monitoring transmission services, auditing the Security Coordinator on a regular basis, and conducting unplanned audits in response to specific complaints of a transmission customer.
The FRCC would remain a reliability-only organization with a voting structure that will ultimately be established by nationwide criteria now being developed. A streamlined FPSC dispute resolution process which would be binding on all parties, would be created through the rulemaking process. FPL and FPC believe that there presently is sufficient authority under the Florida Grid Bill for the FPSC to perform the contemplated activities.
Under the RTS proposal, FPL and FPC also propose to discount transmission service to mitigate "pancaking" of transmission rates within peninsular Florida. These discounted rates would apply to new transactions that occur on or after October 1, 1999.
Public Not-for-Profit Transco Proposal
Jacksonville Electric Authority proposes a non-profit, publicly owned, transmission company (transco) to own and operate the transmission grid in peninsular Florida. The chief benefit of this proposal, according to JEA, is that a robust electric generation market could be facilitated without the accompanying fiduciary obligations to stockholders to maximize return on investment.
The JEA proposal would require substantial amendment to existing law for implementation. One of the difficult issues that would have to be determined, probably ultimately in the courts, is the compensation to be paid to the current owners of the transmission facilities.
Gainesville Regional Utilities (GRU) also filed a proposal supporting a not-for-profit transmission company. Neither JEA nor GRU provided details on how the transco would be developed. A spokesperson representing the City of Tallahassee also spoke favorably of the not-for-profit transco concept, but did not file written comments.
The FPSC will continue to pursue in-state solutions to transmission issues. To this end, an additional Commission workshop will be held to further discuss the three RTO proposals summarized above.
CHAPTER FOURElectric Utility Restructuring
Electric restructuring generally describes a movement from regulated monopoly electric utility services to market-based competitive electric services. A lot of different terms are being used to describe what is happening at the federal level and in other states in the transition to electric competition. Phrases such as restructuring, deregulation, competition, retail wheeling, retail access, and customer choice have all been used to describe a broad-based, national movement away from the traditional rate base regulation of vertically integrated, monopoly public utilities. Regardless of the name attached, what is generally being discussed is the breaking out of generation services into a separate, more competitive segment of the industry while transmission and distribution remain largely regulated monopoly services. These 'unbundled' services would each be priced separately on a customer's bill.
What is Happening in Other States
A number of states are exploring retail restructuring as a way of achieving lower rates and greater customer satisfaction. Higher than average electric rates appear to be the primary driver in these states. Most states experimenting with retail restructuring are using a phase-in system to allow some percentage of retail customers to select from alternative electric generation providers over a window of several years. In a few states, such as California and Massachusetts, all customers will be allowed to choose their generation supplier at once on a date certain. Transmission and distribution services (poles, lines, substations, meters, and monthly billing) will continue to be provided by the regulated utility. Only the generation portion of electric service will be subject to customer choice.
California, New Hampshire, New York, and Massachusetts were among the first states to move toward retail access. The average residential rate in these states is approximately 12 cents per kilowatt-hour (KWH). Because of these high rates, economic development appears to have suffered with the loss of jobs and the relocation of industry. In many high-cost states, large commercial and industrial customers have been the most active in encouraging a move toward competition. At present, a total of twenty-two states have enacted legislation or implemented regulations requiring retail restructuring, although the legal basis is being challenged in several states.
What is Happening in Florida
Florida's electric utility industry has provided very reliable service at competitive prices. On average, Florida's rates have been relatively stable for more than a decade. Adjusting for inflation, the price of electricity in Florida has actually been declining. Compared to prices around the nation, Florida's electric rates continue to be around the national average (approximately 7.2 cents per KWH statewide average). This is particularly commendable given Florida's unique peninsular geography. Florida has little low-cost hydropower, and all our generating fuels must be transported very long distances by rail, pipeline, or water. Also, unlike many other states, Florida's electrical grid is only tied to other utilities in one direction, to the north through the Southern Company. This limits the state's ability to rely on out-of-state purchases.
During the summer of 1996, the FPSC contracted with the University of Florida's Public Utilities Research Center for a series of staff training seminars. Three public forums were held in which experts from around the country addressed many outstanding issues surrounding retail restructuring. These public forums experienced a good turnout from participants representing views from all sides of the issues. Following these training sessions, the FPSC established an in-house team of staff members to continue to monitor and discuss restructuring issues as they develop.
In the national arena, the FPSC has intervened in the FERC's open transmission access docket and has filed comments advocating the preservation of state jurisdiction over transmission and distribution costs currently being paid by retail customers. The FPSC has also been an active participant in the National Association of Regulatory Commissioners (NARUC). Commissioner Susan Clark currently serves as the chair of the NARUC Electricity Committee. This committee plays a pivotal role in developing policy positions on restructuring matters affecting state regulation.
Who is Likely to Gain from Retail Competition
In Florida, as with the rest of the nation, industrial and large commercial customers have been the most vocal advocates of electric restructuring. These customers appear to have the most to gain from restructuring, since their size and business experience give them the ability to negotiate for low-cost generation or to install self-service generation. They also appear to represent the primary market segment to which merchant plants, brokers, and other alternative generation suppliers would most likely target. Small-use residential and commercial customers are less likely to have meaningful alternative generation supply choices in a competitive market and may be left paying higher costs.
One of the primary reasons some states are pursuing retail competition is high electric rates. Florida's electric rates, which are around the national average, have been relatively stable in nominal terms for more than a decade, and when adjusted for inflation, have actually declined by 22 percent. Florida has long supported competition in the wholesale bulk power markets. Savings achieved from the purchase of economic wholesale power alternatives are spread to all electric ratepayers, not a select few. It remains unclear whether all Florida ratepayers would benefit from a mandate for retail competition. In many states that have adopted retail competition, actual program implementation is just now going forward. In some states, implementation has been delayed because of litigation over major issues such as stranded cost recovery.
During the 105th Congress, a number of bills addressing the restructuring of the electric utility industry were introduced. Several bills would have required states to implement retail competition by a date certain. While none of these bills was passed into law, Congress is currently addressing electric utility restructuring in the 106th Congress. The FPSC, in concert with the NARUC, has encouraged Congress to refrain from including a "date certain" mandate in any electric utility restructuring law. The states should be allowed the flexibility to determine if and when retail competition should be enacted and should be free to implement such retail competition in a way that benefits all electric utility customers, not just a select few.
Summary of Individual State Restructuring Activity
The Arizona Corporation Commission (ACC) initially undertook restructuring on its own motion. In 1996, the ACC issued Order 59943 which was a broad blueprint for competition and established staff working groups to deal with specific issues. By December 31, 1997, all utilities subject to ACC jurisdiction (only investor-owned) were to propose for ACC review and approval a plan on how customers will be selected for participation in the competitive market prior to 2003. The investor-owned utilities challenged the ACC's authority, but were ultimately denied by the Arizona Supreme Court. Thereafter, both Arizona Public Service and Tucson Electric Power submitted settlement agreements. Finally, on December 1, 1998, the Arizona Supreme Court blocked approval of the negotiated settlements submitted by these utilities on procedural grounds. Intervenors in the process argued that insufficient time had been allocated for a fair evidentiary hearing. The ACC vacated its order and plans to conduct new hearings on stranded cost and unbundling. This will likely delay implementation by at least a year.
HB 2663 passed the legislature in May, 1998 and applies only to public power utilities. Retail access will continue on schedule for the state's largest public power utility, Salt River Project, with full competition planned no later than December 31, 2000. The legislature mandated that 20 percent of customers could begin to choose alternative retail suppliers by December 31, 1998. The public power utilities have great flexibility to collect stranded costs by way of a temporary surcharge on the distribution portion of the bills. Recovery must end by December, 2004, and participation is required in some type of regional transmission authority or ISO.
SB 791, signed in April, 1999, set the ground rules for retail competition in Arkansas. January 1, 2002 is the initial target date with delays permitted until June, 2003. Municipal and cooperative utilities have the option to open their service areas to competition. Transmission owning utilities must participate in some form of an independent system operation. Nonmitigable and prudently incurred stranded costs and transitional costs are allowed to be recovered, and up to 100 percent can be securitized with PSC approval. Such costs will be recovered by a customer transition charge, and quarterly reports showing the amount of recoverable balances must be provided to the PSC. Rates are to be frozen for three years for utilities seeking recovery of stranded costs.
The PSC must analyze the potential abuse of market power by utilities and new service providers. After appropriate evidentiary hearings, the PSC has broad discretion to adopt mitigation measures including divestiture of generating assets as a last resort. In addition, the PSC must adopt rules for affiliate transactions and use of company personnel across operating companies. Finally, the PSC is charged with adopting rules to address customer protection such as understandable bills, environmental disclosure, and anti-slamming provisions.
The California Public Utilities Commission (CPUC) became involved in electric restructuring as early as 1993 when it issued its first strategy for restructuring. In September, 1996, the California Legislature adopted most of the CPUC plans for restructuring and incorporated them into AB 1890. This law directed the CPUC to make retail access available to all customers by January 1, 1998. The legislature indicated its intent for the stakeholders in the process to negotiate the necessary changes to achieve a competitive retail environment. Publicly-owned electric utilities were encouraged to participate in a retail market. A rate freeze is required between 1998 and 2002 with residential and small commercial accounts entitled to a 10 percent rate reduction.
AB 1890 permits the recovery of stranded costs. The prescribed method to calculate the amount involves netting the negative value of all above market utility generation assets against the positive value of all below market utility owned generation assets. These costs were anticipated to largely be regulatory assets, nuclear assets, and purchased power contracts. Approved costs are permitted recovery through a competitive transition charge. Recovery will not extend beyond December, 2001 except for some transition-related and nuclear costs. Utilities are permitted to use securitization as one means to recover these above market costs.
With respect to market power issues, the act requires that an ISO be formed with a power exchange. The role of the power exchange is to provide an open and centralized auction for buyers and sellers to reveal their prices. In addition, utilities are expected to divest 50 percent of their gas-fired generation. Functional unbundling and rules for affiliate transactions are required. AB 1890 anticipates that billing and metering services will become competitive.
The Act establishes public benefit programs for low income assistance, energy efficiency, R&D programs, and to encourage renewables. Approximately $540 million will be collected over four years by a non-bypassable wires charge.
Early evidence indicates that a substantial amount of industrial load has changed providers. However, few residential customers have switched. Perhaps more notable, a number of energy service providers have developed a market niche selling power that is either partially or fully derived from renewable resources. This so called "green power," while more expensive than non-green power, appeals to some customers, who place a premium on purchasing these kinds of products.
Public Act 98-28, entitled "An Act Concerning Electric Restructuring," was signed on April 29, 1998. This is a detailed, comprehensive restructuring package that provides for full retail choice for all customers by July 1, 2000. Municipal utilities who choose to participate in retail access must open their markets to alternative service providers and auction off their generation assets. Utilities are not required to divest their plants in order to obtain stranded cost recovery. Although securitization is permitted, utilities must attempt to auction both fossil and nuclear plants if they want recovery of stranded costs. Minimum acceptable bids will be prepared by the Connecticut PUC, and the difference between bid and net book values becomes the basis for administratively determining stranded costs. Nuclear plants do not have to be sold or even to receive acceptable bids in order to be eligible to receive stranded cost recovery. A competition transition assessment (CTA) will be developed after netting any proceeds from above book value sales and sales of other company property. Recovery of the CTA will be through 2004.
All utilities must unbundle generation, but transmission and distribution assets may remain with an incumbent. It is anticipated that transmission assets will revert to an ISO. Extensive market structure provisions are included in the Act such as requiring distribution companies to remain providers of last resort, permitting customers to change suppliers once a year without charge, retaining existing consumer protection measures, and specifying standards that must be met before a customer can be switched to a new supplier. This is to prevent slamming. Codes of conduct and affiliate transaction guidelines will be developed by the PUC by January, 1999.
System benefit charges are addressed in the bill. Beginning January 2000, the PUC is to set charges to cover consumer education, low income energy conservation, nuclear decommissioning and fuel storage, worker protection, and payments to municipal governments. In addition, the bill specifies that electric suppliers must provide at least 0.5 percent of their power from renewables. This percentage increases to 6 percent by 2009. A 0.05 ¢/kWh charge is imposed for a Renewables Energy Investment Fund which increases to 0.1¢/kWh in 2004, and an additional 0.3 ¢/kWh charge is imposed for funding energy efficiency programs. Environmental disclosure will also be provided on billing statements.
On March 31, 1999, Governor Carper signed HB 10 entitled the "Electric Utility Restructuring Act of 1999" which mandates a path for retail competition in Delaware. Delaware is served by a single investor-owned utility -- Delmarva Power & Light (now called Conectiv) and a single cooperative -- Delaware Electric Coop (DEC). The bill, like those in many other states, has a phased approach for retail access. The schedule for Conectiv is:
The bill calls for rate freezes for all of Conectiv's non-residential customers from October, 1999 to September, 2002. A 7.5 percent rate reduction will be granted to residential customers for the same period. These caps may be extended one additional year depending on changes to the fuel costs assumed in the rates. A system benefit charge of 0.0095 ¢/kWh is imposed on the IOU for low income assistance programs and an environmental incentive charge of 0.0178 ¢/kWh will also be charged.
Interestingly, while no formal stranded costs are allowed, Conectiv will be permitted to collect some $18 million in costs from industrial customers. Even more notable, HB 10 forbids the use of telemarketing by energy suppliers in Delaware.
With respect to market structure, the Delaware PUC will conduct an inquiry after October 1, 1999 to determine if market power abuse is occurring. Upon an appropriate finding and as a last resort, the PUC can order divestiture of the generating assets of Conectiv. After 2002, the PUC can open up metering and billing to competitors. Conectiv will remain the supplier of last resort to customers who do not choose an alternative supplier, and their rates will be based on "market prices" as determined by the PUC.
The phase-in schedule for DEC is essentially lagged six months with full competition delayed until April 1, 2001. All cooperative utility customers will be entitled to a rate freeze for the period 1998 to 2005. The PUC will administratively determine what stranded costs will be recoverable, and there is no environmental or public benefits charges imposed on the cooperative. However, quarterly generation fuel disclosure information is to be printed on the bills for both types of utilities.
The source for most of Illinois' electric restructuring activity is the "Electric Choice and Rate Relief Act" (HB 362), which was signed into law in December 1997. HB 362 mandates a four stage direct access plan in as follows:
Utilities are permitted partial recovery of stranded costs through transition charges based on "lost revenues." An index of market prices is used as part of a very complex formula for determining the transition charge. The amount of the recovered charge is equal to the value of electricity sold under a tariffed, non-competitive rate minus the so-called competitive or market rate. This difference must be offset by credits gained by the utility for any revenues attributable to delivery charges, newly obtained revenues for being a service provider and the value of avoided energy and capacity that the utility freed up by not having to serve that customer. Finally, a "migration factor" is applied to reduce the lost revenue that begins at 6 percent of 1996 base rates and increases to 10 percent of 1996 base rates by 2006. This factor is simply an estimate of what the utility would be expected to earn in the new competitive environment and is applied against lost revenues even if no new revenues materialize. Securitization is permitted, but 80 percent of the returns on the securitized funds must be used to refinance or retire fuel-related obligations. The utility has until 2006 to collect any stranded costs, but this can be extended until 2008 with PUC permission.
Divestiture is not required, but functional unbundling of generation, transmission, and distribution is mandated by HB 362. Utilities do have broad authority to divest, lease, or transfer assets during the transition period into a fully competitive market. The utilities are encouraged to join a regional ISO to further mitigate market power, but failure to do so will lead to the formation of an Illinois ISO. Finally, the PUC has the discretion to issue and require codes of conduct and standards for affiliate transactions.
Nonresidential rates are frozen through 2004 at the 1996 levels. Residential customers of ComEd and Illinois Power will receive a 15 percent rate reduction in 1998 followed by 5 percent more in 2002. For other Illinois utilities, lower rate reductions are mandated in the bill.
Finally, public benefit charges will be collected to encourage the use of renewable and clean coal-generated energy. Disclosure of generating fuels will be required on all bills.
In July, 1995, the Maine Legislature directed the Maine Public Utilities Commission (MPUC) to devise a plan for the Legislature to consider which would achieve retail competition in the electricity market. The final report and plan were presented on December 31, 1996. On May 29, 1997, the Governor signed into law LD 1804, "An Act to Restructure the state's Electric Industry" (the Act). It provides for full retail competition to begin on March 1, 2000. It directs the MPUC to conduct rulemaking on several issues that must be addressed to implement retail access. Between the Fall of 1997 and the Fall of 1999, the MPUC will conduct 13 rulemakings on subjects such as unbundling, metering, consumer education, and renewable resources.
Under the provisions of the Act, all consumers of electricity will have the right to purchase generation services directly from competitive providers beginning on March 1, 2000. Beginning March 1, 2002, the provision of metering and billing services will be subject to competition. The MPUC is empowered to establish an earlier date for the provision of these services by rule, but the date can be no earlier than March 1, 2000.
Prior to October 1, 1999, the MPUC will complete an adjudicatory proceeding to address the design of transmission and distribution rates to recover stranded costs, transmission and distribution costs, decommissioning expenses for nuclear units, and any other charge required by law.
Before the start of retail access, the MPUC will estimate the stranded costs for each utility, and use those estimates to set a stranded cost charge to be collected by the transmission and distribution utilities when retail access begins. This will be done in the MPUC's adjudicatory proceedings ending by July 1, 1999. In 2003 and every three years after that, the Commission will correct any substantial inaccuracies in the stranded cost estimates except for those stranded costs associated with divested generation assets, and change the transmission a distribution charge accordingly. The Commission may also adjust the charge at any other time. Any changes to the stranded cost charge are to be made on a prospective basis and cannot address past inaccuracies in stranded cost estimates. In setting the stranded cost charges, the MPUC may not shift recovery of stranded costs among customer classes in a manner inconsistent with existing law.
The Act requires that on or before March 1, 2000, investor-owned electric utilities must divest all generation assets and generation-related business activities. Certain assets, such as contracts with qualifying facilities, contracts with demand-side management or conservation providers, ownership interest in nuclear units, and certain essential facilities, do not have to be divested.
Finally, Maine has a renewable portfolio standard which requires that at least 30 percent of generation must be derived from renewable resources. While this is a very high percentage, Maine does count its abundant hydro power resources toward this renewable standard. Additionally, distribution utilities must continue to offer energy efficiency programs and include them in their existing rates.
In April, 1999, Maryland's governor signed a reconciled version of HB703 and SB300 which mandates retail competition. The bill sets startup dates of July 2000, for one-third of all residential customers, and within three years all customers will have the option to shop for alternative providers. Commercial and industrial customers may select providers beginning in January, 2001. Cooperatives must participate by 2003, but municipal utilities have an opt-out provision. This law largely supports the PSC-initiated restructuring proposals.
Full recovery of prudent and verifiable stranded cost is permitted by way of a customer transition charge. However, the PSC can require alternative collection mechanisms. Securitization is permitted.
The utilities must functionally unbundle their operations, but the PSC cannot require divestiture or prohibit voluntary divestiture of generating assets. If the PSC finds market power concerns, then it may take action within its prescribed authority or refer the case to the Maryland Attorney General's office.
Rates will be capped for at least four years. In addition, the PSC has discretion to reduce rates between 3 and 7.5 percent of June, 1999's base rates. The PSC must also develop procedures and rules addressing customer service and protection issues for all competitive suppliers. Disclosure of generation fuels and air quality impacts is required.
Maryland's law is flexible with respect to public benefits. A universal service fund of $34 million is to be established for low income customers. Utilities cannot generate less renewable energy than they did in 1998, and the PSC will report by 2000 on the feasibility of requiring a renewable portfolio standard. Finally, the Maryland Department of Environmental Quality must report on the impacts of deregulation on air quality.
Massachusetts is one of the fully-transitioned states. It passed its restructuring law in November, 1997 and largely affirmed the PUC order issued a year earlier to guide the restructuring process. The implementation date was set for March, 1998, and it was to be accompanied by a 10 percent rate reduction. Another 5 percent reduction is required by September, 1999. Municipal utilities have the option to participate.
Recovery of stranded costs is permitted if conforming utilities properly demonstrate that they have divested all non-nuclear generation and attempted to mitigate all other costs. Utilities may then use securitization to help with recovery. If a utility is unwilling to divest its generation, then the Massachusetts Department of Telecommunications and Energy (DTE) will administratively determine the amount of stranded costs.
Unbundling of services and codes of conduct are required. While participation in an ISO or power exchange is not mandated in the act, it assumes an ISO or equivalent structure will be formed in the New England Power Pool (NEPOOL) control area.
With respect to public benefit programs, distribution companies must offer low income discounts, a Renewable Energy Trust Fund is established, beginning with a fee of 0.075 ¢/kWh in 1998 which increases to 0.125 ¢/kWh in 2000 and then phases down, and a charge of 0.33 ¢/kWh is established for funding energy efficiency programs. This fee is phased down to 0.25 ¢/kWh in 2002. Finally, a renewable portfolio standard is mandated, but hydro is considered an acceptable form of renewable energy. One percent new renewables are mandated by 2003. This rises by 0.5 percent each year until 2009 and then increases 1 percent per year thereafter.
At the behest of Governor John Engler, the Michigan Jobs Commission completed their recommendations entitled A Framework for Electric and Gas Utility Reform in January, 1996. The report recommended six near-term objectives be achieved by January 1, 1997. These recommendations were: 1) allowing direct retail access for commercial and industrial accounts, 2) addressing stranded costs, 3) exploring replacing rate of return regulation with rate cap regulation, 4) allowing immediate file and use tariffs, 5) eliminating prescriptive regulatory measures, and 6) reorganizing the Michigan Public Service Commission (MPSC). Public hearings were conducted on the recommendations during the summer of 1996, and MPSC staff submitted their Staff Report in December, 1996. The Staff Report recommended that: 1) all customers -- not just commercial and industrials -- should be permitted to participate in retail access, and 2) rates should not increase for any customers and should decrease where possible. On June 5, 1997, the MPSC voted to adopt, for the most part, the restructuring strategy outlined in the Staff Report.
While the substantive aspects of the MPSC's implementation order were not appealed, challenges based on jurisdictional issues were filed. On June 19, pursuant to the MPSC's order, Detroit Edison and Consumers Energy submitted their proposed tariffs and requirements to begin restructuring. Interestingly, based in part on jurisdictional questions, both companies filed these tariffs as voluntary and conditional. Detroit Edison said it would proceed with the "voluntary" program if the MPSC approved it and the legislature approved securitization and authorized recovery of stranded costs.
In June, 1999, the Michigan Supreme Court ruled 4 to 3 that the MPSC exceeded its authority in issuing the restructuring order. This decision reversed an appeals court decision in support of the MPSC action. Discussions with MPSC staff indicated it is unclear what this means for retail competition in Michigan.
SB 390 (the Electric Utility Industry Restructuring and Customer Choice Act) was approved by the legislature and signed into law on May 2, 1997. The new law calls for retail choice for larger customers and pilot programs for smaller customers to begin on July 1, 1998. As soon as administratively feasible, but before July 1, 2002, all other customers must have retail choice. The PSC may extend the date for two years if it finds that it is not administratively feasible or that there is not workable competition. Utilities must file restructuring plans by July 1, 1997.
To the extent that a public utility is vertically integrated, a public utility must functionally separate the utility's electric supply, retail transmission and distribution, and unregulated retail energy services operations. The PSC may not order a public utility to divest itself of any generation assets or prohibit a public utility from voluntarily making such a divestiture. Montana Power, which serves most of the state, divested its entire portfolio of generation facilities during 1998.
The PSC shall allow recovery of unmitigable purchased power contracts, regulatory assets, and non-economic generation. Upon PSC approval of these costs, they can be recovered through a non-bypassable charge on all customers. A utility may, after July 1, 1997, apply to the PSC for a determination that certain transition costs may be recovered through issuance of transition bonds. If transition bonds are issued, the cost savings associated with the bonds must benefit customers. The utility retains sole discretion whether to sell, assign, or otherwise transfer or pledge, transition property.
Beginning January 1, 1999, 2.4% of each utility's annual retail sales revenue for the calendar year ending December 31, 1995, is established as the annual funding level for universal system benefits programs. This funding level remains in effect until July 1, 2003. These funds will be used to ensure continued funding of and new expenditures for energy conservation, renewable resource projects, and low-income energy assistance during the transition period and into the future.
The Nevada Public Utilities Commission (Commission) prepared a draft bill on restructuring on February 6, 1997. This bill required the Commission to adopt restructuring rules within 18 months of approval and to oversee the restructuring process. This draft bill was formally introduced as Assembly Bill 366 (AB 366) on April 15, 1997. The Nevada Legislature ultimately passed AB 366 and the Governor signed the bill on July 16, 1997. The law permits retail access on December 31, 1999. The law also includes stranded cost recovery standards, competition guidelines for utility affiliates, distribution utility performance-based regulation, a renewables portfolio standard, consumer protections, and alternative supplier licensing.
Under the AB 366, the Commission will determine the recoverable costs associated with potentially competitive service as of the date on which alternative sellers begin providing the service. In determining stranded costs, the Commission will consider: 1) the extent to which the utility was legally required to incur the cost, 2) the extent to which the market value exceeds the cost, 3) the utility's efforts to mitigate the costs, 4) the extent to which rates previously set compensated shareholders for the risk of nonrecovery of the costs, 5) the effects of the difference between the market value and the cost, and 6) the utility's management practices compared to other utilities with similar obligations to serve.
The Commission must establish standards of conduct for competitive markets and monitor the markets for anticompetitive or discriminatory practices. The law also gives the Commission authority to set conditions and limitations on the ownership, operation, and control of a service providers assets in order to prevent anticompetitive behavior. The Commission also must conduct investigations to assess the effect of mergers, disposition of ownership or control of assets, transmission congestion, and anticompetitive behavior.
The law establishes a renewable portfolio standard for wind, solar, geothermal, and biomass. The goal is for renewables to provide one percent of Nevada's total electric needs. The standard must be derived from not less than 50 percent solar. The Commission may establish a system of credits to facilitate compliance. Credits must be issued for each kWh of renewable energy produced, and holders may trade or sell the credits.
One of the most interesting and unique aspects of Nevada's restructuring law is that it keeps the Commission involved in assuring adequate generating facilities are built. The new law requires the Commission to develop regular forecasts of electric capacity and energy. Providers of competitive services (i.e., end-use electricity providers) are to annually submit information to the Commission allowing it to monitor the development of competition and to ensure the availability of adequate, reliable, efficient, and economic electric service. If the Commission determines that insufficient capacity is forecasted, it may take remedial actions. The Commission may establish equitable, non-discriminatory obligations for customers, electric distribution utilities, or alternative sellers to ensure sufficient capacity is available.
In May, 1996, HB 1392 (codified at RSA 374-F) was signed, calling for full retail access by March, 1998. In response, the New Hampshire PUC issued its Final Plan on February 28, 1997. This plan is the blueprint of the market and institutional structures necessary to provide customers with energy service choices and to ensure fair and efficient competition among retail market participants. The Final Plan directed each utility to file comprehensive plans, no later than June 30, 1997, which comply with the Final Plan and the supplemental orders.
In response to the Final Plan, Northeast Utilities (NU), parent of Public Service Company of New Hampshire (PSNH), filed suit in federal court on March 3, 1997. NU claimed that the restructuring order would illegally impose economic losses on PSNH and violate a 1989 rate agreement with the state. A federal judge agreed in part with the NU claims and issued a temporary restraining order limited to the issue of stranded cost recovery for PSNH. The judge also ordered the parties (i.e., the mediator, governor, state attorney general, and PSNH representatives) into a mediation process with a September 2, 1997 resolution deadline. However, the parties were unable to reach agreement.
Due to this delay, the New Hampshire Legislature passed SB 341 which delays the March, 1998 implementation date and allows negotiated settlements to achieve retail access. Finally, in June, 1999, a memorandum of understanding (MOU) was negotiated between the PSNH and the parties to the federal lawsuit. This MOU attempts to resolve the two-year federal court challenges to the PUC plan. Key highlights of the settlement call for PSNH to recover up to 85 percent of its stranded cost with up to $725 million to be securitized, to divest its plants and purchased power agreements, to immediately reduce rates by 18 percent, to continue to operate as a distribution and transmission company, and to collect system benefits charges totaling some $28 million over three years.
A law labeled A 16, "The Electric Discount and Energy Competition Act," was passed by the legislature in January 1999 and signed by the Governor on February 9, 1999. The law requires the New Jersey Board of Public Utilities (BPU) to open up the state's retail electricity market by August 1, 1999 and the retail natural gas market by December 31, 1999. Consumers will receive a 5 percent discount off their electric bills when competition starts and at least another 5 percent discount over the next three years. The BPU must decide the exact amount and timing of the second rate discount. Municipal and cooperative utilities are exempt from the act.
The BPU will determine the amount of stranded costs the utilities will be entitled to recover. Mitigation efforts are required. New Jersey will also use a competitive transition charge for recovery. Eight years is provided to recover stranded costs with the BPU having authority to extend this for certain kinds of assets ( cogeneration contracts, generating assets greater than 20 percent of the total stranded costs and with longer than 10 years operating life).
Securitization is permitted for up to 75 percent of stranded costs and up to 100 percent for those utilities who divest generation. The BPU may require divestiture if market conditions warrant, and utilities must functionally unbundle competitive and noncompetitive services. Standards of conduct will be developed.
System benefit charges for energy efficiency and social programs are mandated. Every 4 years, the BPU will undertake a proceeding to determine the amount of funding for energy efficiency and renewables. For the first 4 years, the total amount must equal 50 percent of the amount currently being collected in regulated rates. Finally, a low income universal service fund is established.
New York was one of the few states to use a different strategy to deregulate electric retail service. It did not have a legislative directive to restructure, but on May 16, 1996, the New York Public Service Commission (PSC) issued its plan (the "Competitive Opportunities Case," Opinion and Order No. 96-12) to introduce retail competition to the state. That order outlined the PSC's vision of what the restructured market should look like. The order required five IOU utilities (Orange and Rockland, Consolidated Edison, Rochester Gas and Electric, New York State Electric and Gas, Central Hudson) to file restructuring proposals and rate plans by October 1, 1996. Niagara Mohawk had already filed a proposal in 1995, and Long Island Lighting Company was not required to file because of the involvement of the Long Island Power Authority in their acquisition. The PSC believed, due to the differing circumstances of each utility, that restructuring plans were best addressed on an individual company basis. Following the filing of the utility plans, the PSC staff engaged in negotiations with each company to reach a settlement agreement.
In response to the PSC's May, 1996 order (Opinion 96-12) requiring utilities to file restructuring plans, the New York utilities filed suit against the PSC, claiming that it did not have jurisdiction to implement retail access or to mandate divestiture of generation assets. The case went to the New York Supreme Court which determined that the PSC, under New York law, has such jurisdiction. Consequently, the rate and restructuring proceeding continued.
The access dates approved in the final settlements varied by utility, but all used phase-in schedules. It is anticipated that full retail access will be available by July, 2001. However, customers of New York State Electric and Gas and Niagara Mohawk are scheduled to have full choice by August, 1999. All the orders call for either electric rate reductions or freezes for all classes of customers, whether or not such customers choose to purchase their electricity from an alternative supplier.
The settlements commit the utilities to divest most fossil generation. Codes of conduct are being developed. While stranded cost estimates were not addressed in the order, the order indicates utilities should have a "reasonable opportunity to recover strandable costs."
A significant issue in the restructuring proceedings was the maintenance of environmental protection and other public policy goals. In Opinion 96-12, the PSC directed that a non- bypassable system benefits charge be established to support investments in energy efficiency, research, development and demonstration, low income programs and environmental monitoring that might not be fully supported in a competitive market. Statewide, about $233 million in system benefits charges funds will be collected through wires charges over the three year period. The PSC designated the New York State Energy Research and Development Authority to be the statewide administrator for the system benefits charges program.
In April, 1999, SB 428 was signed, permitting retail competition in New Mexico. The New Mexico Supreme Court had ruled that the PSC did not have the authority to permit retail competition, and had vacated certain PSC orders to that affect. This new statute provides the enabling authority to permit such competition. January 1, 2002 is the initial choice date for residential and small commercial accounts with full access for all customers by January, 2002. Cooperatives and municipal utilities have the option to open their markets to retail competition. These entities will remain regulated by the newly-created New Mexico Public Regulatory Commission (PRC).
Subject utilities can collect up to 50 percent of unmitigable stranded cost by a surcharge on energy sales. The PRC can allow more than 50 percent recovery if such recovery does not raise residential or small commercial rates. Other standards must also be met as such recovery is necessary for reliability, to ensure financial operations, and to be in the public interest. The recovery period for stranded costs is through 2004, and other transition costs may be recovered until 2007.
Affected utilities must unbundle generation from transmission, distribution, and billing and collections. However, divestiture is not required. The PRC will adopt rules to address customer service, disclosure requirements and education functions. The PRC must also adopt codes of conduct to prevent inappropriate affiliate and noncompetitive transactions.
A system benefits charge of 0.03 ¢/kWh will be imposed beginning in 2002. This should collect about $5 million per year with the charge doubling to 0.06 ¢/kWH in 2007. The funds will be used for low income assistance, extending renewable energy to unserved communities, and educating consumers. <
In June, 1999, Governor Taft of Ohio signed SB 3. This bill expressly declares that beginning on January 1, 2001, retail electric generation, aggregation, power marketing, and brokerage services to consumers is deemed to be competitive. However, the PUC may delay this initial competitive date for up to six months. The transition period to a fully competitive market will be through December 31, 2005, or until all transition costs are recovered, whichever occurs first. The PUC also has the authority after an appropriate hearing to make billing, metering, and collections competitive.
Divestiture is permitted without PUC approval, but the act does give specific authority to the PUC over mergers and acquisitions and allows the PUC to intercede in cases where it suspects undue market power or where any utility interferes with a competitive market. In addition, by January 1, 2000, the incumbent utilities must submit a "corporate separation plan" that amounts to functional unbundling of services. Finally, an Independent System Operator is required to operate transmission assets.
During the market development period (up to 2005), all existing rates and charges will be unbundled on the bill and capped at their existing level with the exception of the generation portion, which shall be reduced by 5 percent.
The value of stranded costs and transition costs shall be administratively determined by the PUC and may be recovered through 2005. Such costs will be recovered through a customer transition charge. Recovery is permitted for regulatory assets (nuclear decommissioning and disposal costs, undepreciated radiation safety equipment, etc.) no later than 2010.
The act requires disclosure of the environmental characteristics of the energy produced (coal, nuclear, renewable, etc.) and creates a revolving loan fund of approximately $100 million over ten years for energy efficiency loans to residential customers, schools, small commercial customers, government accounts, and agricultural customers. Programs for low-income customers are consolidated within the Department of Development.
Oklahoma Senate Bill 500, also known as the "Electric Restructuring Act of 1997," was approved on April 23, 1997. It requires that direct access be made available to retail consumers no later than July 1, 2002. In the event the state does not adopt a uniform state tax structure by this time, the start date for direct access will be deferred. The bill grants the Oklahoma Corporation Commission (OCC) considerable oversight of the details of the restructuring effort, but it also requires the OCC to study and report on a number of important issues which will ultimately be determined by a joint legislative restructuring task force. The task force, identified as the Joint Electric Utility Task Force, is comprised of 14 members, drawn equally from the state house and senate chambers.
The OCC is required by Senate Bill 500 to establish procedures for identifying stranded investment, quantifying stranded costs, and proposing a mechanism for the recovery of such costs. Utilities are required to determine the level of their stranded costs and identify a limited time period over which they can be recovered without raising rates. The costs are to be fully recovered over a three- to seven-year period. The Joint Electric Task Force must receive the OCC's report on stranded costs and other financial issues no later than December 31, 1999. Per Senate Bill 500, the application of the transition charge designed to recover stranded costs will not advantage one class of customers over another. An OCC report regarding consumer issues is due to the Joint Electric Utility Task Force by August 31, 2000.
In terms of market power, the bill calls for a task force report to address the formation of an independent system operator and power exchange (PX); functional unbundling of generation, transmission, and distribution; bill unbundling; and other methods of achieving open access. Other task force reports will address reliability, public purpose programs, and tax issues.
On November 25, 1996, the Pennsylvania Legislature voted to adopt HB 1509, "The Electricity Generation Customer Choice and Competition Act" (the Act). On December 3, 1996, Governor Tom Ridge signed the Act into law. Essentially, the Act restructures the electric industry by separating the services of generating electricity from the services of transmitting and distributing electricity. The Act permits customers to choose their electricity generation supplier, but requires them to purchase transmission and distribution services from their traditional electric utility. All subject utilities were required to file restructuring plans with the Pennsylvania Public Utilities Commission (PPUC) between April 1, 1997, and September 30, 1997.
The PPUC has established industry working groups to provide recommendations on areas of concern that have arisen in the restructuring process. These areas include consumer education, customer information and billing, universal service, conservation, reliability, direct retail access implementation schedule, metering, competitive safeguards, interaction between suppliers and customer utilities, and taxes.
The statute calls for a phase-in for allowing retail customers the right to choose. It provides that a maximum of 33% of the peak load of each customer class shall be eligible for direct access by January 1, 1999. A maximum of 66% of the peak load of each customer class shall be eligible for direct access by January 1, 2000, and all customers in the state shall be eligible by January 1, 2001.
The PPUC is authorized by the Act to determine the level of stranded costs that each utility is permitted to recover. The Act precludes cost-shifting between customers as a consequence of stranded cost recovery. Such costs can be recovered through a non-bypassable competitive transition charge (CTC) that will be reviewed annually and adjusted annually for each customer of the utility who elects to receive service from an alternative generation supplier. The CTC will be collected by utilities over a maximum period of nine years, unless the PPUC approves an alternate period.
The Act encourages, but does not mandate, market participants to coordinate their plans and transactions through an independent system operator or functional equivalent. It permits, but does not require, electric utilities to divest themselves of facilities or to reorganize their corporate structures, but unbundling of services is required.
Public benefits programs are funded by an energy surcharge to provide programs for low-income assistance, energy conservation, and other public purposes at the existing funding levels.
On June 18, 1999, Governor George W. Bush signed SB 7 that introduced retail competition in Texas. The bill mandates full retail access for all customers of investor-owned utilities by January 1, 2002, with the exception that if the Texas PUC finds that a region is not competitive, it can delay the retail access date. Municipal and cooperative utilities have the option to offer retail access after this date but are not mandated to do so. An interesting aspect of the Texas law prohibits competitors from only serving the more profitable industrial loads. To ensure that new electric providers do not selectively market only to large volume users, the law provides that any new competitor that serves at least 300 MWs of load must also serve at least 5 percent of the residential class or, alternatively, make payments to a systems benefit fund.
Recovery of stranded costs that cannot be mitigated is permitted, with the industrial and interruptible customers paying a disproportionate share. Up to 75 percent of stranded cost may be eligible for securitization. The act requires that generating utilities divest a percentage of their generating assets, and they are required to functionally separate their companies into power generation, retail service provider, and transmission and distribution affiliates.
A systems benefit charge (SBC) is set at $.50/mWh is set on all sales until 2001 at which time the PUC can increase it to $.65/MWH. The proceeds from this charge will be allocated to low-income assistance, education programs, and public schools. Revenues from the SBC will be administered as a trust fund by the PUC. In addition, the bill requires a phase-in of renewable generation resources with an ultimate goal of 2880 MWs by 2009. This is approximately 3 percent of forecasted generation. In addition, the legislature wants 50 percent of new generation to be fueled by natural gas and requires a credits trading program to achieve this. Interestingly, the bill defines natural gas-derived electricity as "green electricity" because of its perceived favorable environmental impact.
Finally, the PUC will undertake a series of task forces to do the necessary rulemaking to implement the provisions of SB 7. The goal is to begin the pilot programs by June 1, 2001.
On October 17, 1994, the Vermont Public Service Board (the Board) opened an investigation (Docket No. 5854) with the aim of advancing restructuring through an open, more formal process. After a series of workshops and technical conferences, the Board issued a draft report and order on October 16, 1996. A final report and order were issued on December 31, 1996 based on the comments received on the draft report and order. This document, entitled "The Power to Choose: A Plan to Provide Customer Choice of Electricity Suppliers," included the Board's recommendations for electric restructuring.
On April 3, 1997, the Vermont Senate adopted a majority of the Board's recommendations in Senate Bill 62 (SB 62). The Vermont House of Representatives did not bring SB 62 up for a vote, and it stalled in committee. The House postponed formal consideration of restructuring. As a result of the actions in the Vermont Legislature, the Board suspended all hearings and activities associated with its restructuring plan. Formal restructuring activities will resume pending legislative approval.
On July 22, 1998, the Governor signed an executive order creating a five-member "Working Group on Vermont's Electricity System." The working group was directed to study restructuring activities regionally and nationally, the effects of the Hydro-Quebec contract on ratepayers, the state's competitive position within a deregulated environment, and the effect of recent regulatory activities on Vermont utilities. On December 18, 1998, the Working Group submitted its final report to the Governor who has endorsed the document and requested its immediate implementation. The report suggests that the Vermont electric system needs to be restructured and that the process should begin within the next 18 months.
In December, 1998, the Virginia State Corporation Commission (SCC) issued interim procedures to require pilot programs for electric and gas retail competition. Virginia adopted restructuring legislation (SB 1269) in April, 1998. The legislation is broadly written and does not go into specific details of implementation. It prescribes that future SCC and general assembly actions will be required for full implementation.
The Act broadly defines six requirements. These are:
The requirements for pilot programs continue in force. American Electric Power plans to submit a revised pilot program to permit about 2 percent of its load to have retail choice. Virginia Electric Power has plans to permit about 7 percent of its residential/commercial load to have retail choice by June 2000. This program would continue until full implementation in 2002, as prescribed by the restructuring act.
Conclusion to Individual State Restructuring Activity
As illustrated above, the states that are experimenting with retail access are at the beginning stages of that process. Some states are further along than others. The framework and safeguards that each state has adopted clearly shows the advantage of state legislatures and commissions asserting their traditional role of ensuring that retail competition benefits all classes of ratepayers in their respective states. The diversity of these approaches argues against a Federal mandate that would impose a "one size fits all" model on the states.
While it is too early to reach many conclusions, a couple of tentative observations can be made. First, in those states that have full retail access, the large industrial customers are most likely to have alternative suppliers to choose from, and to exercise their rights to obtain these new generation sources. It is also evident that residential customers have fewer real choices than larger customers, and therefore fewer residential customers are switching than anticipated. Second, states for the most part have been able to implement solutions to address stranded costs. Utilities that have been required to divest their generation and sell it on the open market have generally received offers substantially above what had been anticipated. Where divestiture has not been required, many states have adopted procedures to permit securitization for any remaining stranded costs. This has served to slow the transition to an open retail market. Third, those states which have crafted consumer protections and information disclosures to help assist customers have been more successful in reducing customer dissatisfaction during the transition to retail competition. Finally, it is too early to assess what consequences the transition to retail access will have on reducing overall customer rates. Some recent price spikes on the wholesale market in the Midwest have reached extremely high levels; however, they have been for short enough duration not to affect the overall cost of electricity. It is too early to foresee whether competition will develop to the level necessary to ensure adequate supplies of electricity while placing downward pressure on rates.
Operational Merchant Plants1
1Source: Merchant Power Scoreboard
2Source: Energy Information Administration
Merchant Plants Under Construction or Under Development1
1 Source: Merchant Power Scoreboard
2Source: Energy Information Administration
Reported Plans for Merchant Plants1
1Source: Merchant Power Scoreboard and Energy Information Administration
Proposed Characteristics of an RTO
At a minimum, an RTO must have the following characteristics:1
Approved Transmission Entities
ISO New England
Utilities in Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island, and Vermont created ISO New England through a voluntary agreement of participants to achieve compliance with Order No. 888. ISO New England's Board of Directors is comprised of ten independent members. ISO New England received conditional FERC approval on June 25, 1997. (3) FERC's approval was contingent upon ISO New England codifying its policy to allow non-ISO members to participate in the ADR process.
New York ISO
Utilities in New York created an independent transmission operator through a voluntary agreement of participants to achieve compliance with Order No. 888. The New York ISO's Board of Directors is comprised of 10 independent members. The New York ISO received conditional FERC approval on June 30, 1998.2
With its conditional approval, FERC deferred its decision on whether the New York ISO has a single, unbundled, grid-wide tariff to all eligible users and whether the New York ISO promotes efficient use, and investment in, generation, transmission, and consumption of electricity. Also, the New York ISO recognized the need to develop additional arrangements to coordinate with adjacent power pools.
Pennsylvania-New Jersey-Maryland (PJM) ISO
Utilities in Delaware, Maryland, Pennsylvania, New Jersey, Virginia, and the District of Columbia have created the Pennsylvania-New Jersey-Maryland ISO (PJM ISO) through a voluntary agreement of participants to achieve compliance with Order No. 888. PJM ISO received conditional
FERC approval in November, 1997 (4) and started operations in April, 1998. The PJM ISO's Board of Directors is comprised of 8 independent members. With its conditional approval, PJM ISO has agreed to modify its Operating Agreement to prohibit the ISO from contracting with a participant for goods and services without an open and competitive bidding process.
Utilities in Illinois, Indiana, Kentucky, Maryland, Missouri, Ohio, Pennsylvania, Virginia, West Virginia, and Wisconsin have created the Midwest ISO (MISO) through a voluntary agreement of participants to achieve compliance with Order No. 888. MISO received conditional approval from FERC in September, 1998. (5) MISO's Board of Directors is comprised of 8 independent members. MISO expects to be fully functional by 2001. As a condition of FERC approval, MISO must follow through with its commitment to serve as Security Coordinator to ensure short-term reliability of grid operations.
The California ISO (Cal-ISO) received FERC approval in October, 1997 (6) and became operational on March 31, 1998. The Cal-ISO was created as part of California's efforts to de-regulate its retail electric utility industry. (A.B. 1890). The Cal-ISO's Board of Governors consists of 24 members. FERC granted a waiver of its OASIS requirements on an interim basis because the proposed Wenet meets the current needs of the WEPEX Market Participants, including the ISO's transmission customers. However, Cal-ISO will eventually need to comply with FERC's OASIS requirements.
The California Electricity Oversight Board (EOB), Cal-ISO's primary regulatory agency, monitors, evaluates, and represents the state's interests concerning the operation and reliability of the interconnected electric transmission system. However, California is considering establishing a new energy "superagency" to plan and site new electric and gas transmission and to exercise eminent domain power. The California Energy Reliability Agency would replace the current California Energy Commission and the EOB, as well as some of the functions of the California PUC and the Cal-ISO. The impetus behind this new agency is concern by elected officials that the stakeholder component of the ISO's board would be at odds with the public interest (i.e., utilities and competitive generators sit on the board of directors for Cal-ISO). The new reliability agency, composed of a 5-member commission made up of legislators and technical energy experts, would site transmission lines and gas pipelines, develop transmission plans for the future, certify new generators, exercise eminent domain, and administer energy-efficiency programs. (7)
Because its boundaries are coincident with the intrastate ERCOT Interconnection boundaries, the state of Texas has jurisdiction. Hence, the Texas Legislature amended the state's Public Utility Regulatory Act in 1995 to deregulate the wholesale generation market. Subsequently, Public Utility Commission of Texas (PUCT) Rule 25.197 authorized an ISO in order to foster a healthy wholesale market within ERCOT. Finally, the PUCT established the ERCOT ISO by order on August 21, 1996. (8) The ISO's Board of Directors are comprised of three members from six market groups: investor-owned utilities; generation-owning or transmission-owning municipal utilities; generation-owning or transmission-owning electric cooperatives; transmission-dependent utilities; independent power producers; and power marketers.