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INTRODUCTION
Retail Sales
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.
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Wholesale Sales
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.
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CHAPTER TWO
WHOLESALE COMPETITION
Background
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.
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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.
|
Percent of 1998 Operating Revenues by Type of Wholesale Sale
|
|
Energy Broker Sales |
Non-Broker Opportunity Sales |
Long-Term Wholesale Sales
|
|
Florida Power Company |
0.12% |
1.63% |
6.17% |
|
Florida Power & Light Corporation |
0.08% |
1.90% |
1.31% |
|
Tampa Electric Company |
1.66% |
0.21% |
7.26% |
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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.
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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.
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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.
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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.
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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.
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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.
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Reliant Energy
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.
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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.
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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)
|
Stage of Development |
Merchant Capacity
|
|
Currently Operational |
13,349 MW |
|
Under Construction or Development |
14,886 MW |
|
Reported Plans for Merchant Plants |
56,021 MW |
|
Total |
84,256 MW |
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.
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CHAPTER THREE
TRANSMISSION
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.
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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.
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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.
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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.
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ITA Proposal
The ITA proposal was developed and submitted by the following entities:
- Constellation Power Development, Inc.
- Duke Energy New Smyrna Beach Power Company LTD., L.L.P.
- Florida Municipal Power Agency
- Orlando Utilities Commission
- Reliant Energy, Inc.
- Seminole Electric Cooperative, Inc.
- Tampa Electric Company
- U.S. Generating Company
This proposal provides that the ITA would oversee and administer the planning and
operation of peninsular Florida transmission grid facilities. The ITA would administer
an Open Access Transmission Tariff for peninsular Florida that would provide fair,
equitable, and non-discriminatory access and use by all eligible users. The current
functions of the Florida Reliability Coordinating Council (FRCC) would be merged
with the ITA, and efforts would be made to use the existing FRCC infrastructure
under the ITA governance structure. The FRCC is currently one of ten reliability
councils that make up the North American Electric Reliability Council (NERC). Each
of these entities is responsible for ensuring and enhancing the reliability and
adequacy of bulk power electricity supply in well-defined geographical and electrical
regions in North America. The FRCC oversees the reliability of the region of Florida
that lies east of the Appalachicola River, commonly referred to as peninsular Florida.
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.
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RTS Proposal
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.
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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.
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CHAPTER FOUR
RETAIL COMPETITION
Electric 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.
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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.
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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.
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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.
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Summary of Individual State Restructuring Activity
Arizona
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.
Arkansas
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.
California
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.
Connecticut
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.
Delaware
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:
- peak loads greater than 1 MW can choose alternative suppliers by October 1, 1999
- peak loads greater than 300 KW can choose by January 15, 2000
- all others (including residential) will have choice by October 1, 2000
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.
Illinois
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:
- Stage 1: By 10/1/1999 all of the following customer types are eligible:
- 1) all customers with individuals loads > 4000 kW;
- 2) all commercial retail customers with 10 or more separate locations which aggregate
to > 9,500 kW; and
- 3) 1/3 of the customers in each non-residential retail customer class (based on
lottery).
- Stage 2: By 10/1/2000, all governmental customers with > 9,500 kW are eligible.
- Stage 3: By 12/31/2000, all remaining non-residential retail customers are eligible.
- Stage 4: By 5/1/2002, all residential retail customers are eligible.
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.
Maine
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.
Maryland
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
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.
Michigan
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.
Montana
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.
Nevada
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.
New Hampshire
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.
New Jersey
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
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.
New Mexico
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. <
Ohio
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
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.
Pennsylvania
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.
Texas
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.
Vermont
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.
Virginia<
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:
- Necessary ISOs or regional transmission authorities and power exchanges should be
established by January, 2001. This apparently will be a joint exercise between stakeholders
and the SCC;
- Transition to competition is to begin by January, 2002, with full retail access
by January, 2004;
- Just and reasonable stranded costs are to be recovered;
- Any implementation requirements must ensure reliability and just and fair rates
for all classes;
- Any implementation decisions should recognize unique financial and tax conditions
of all utilities and cooperatives; and,
- Pending legislation or SCC actions will not be affected by the statute;
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.
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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.
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Appendix B
Operational Merchant Plants1
|
State
|
Number of merchant plants acquired from utility divestiture |
MW
|
Parent Company |
Status of Retail Restructuring Legislation 2 |
|
California |
16 |
10,594
|
Houston Industries, NRG/Dynergy Power, Thermo Ecoteck, AES, Duke Energy, Sunlaw
Energy |
Enacted |
|
Colorado |
1 |
80 |
Citizens Power |
Ongoing Investigation |
|
Connecticut |
1 |
520 |
Bridgeport Energy |
Enacted |
|
Maine |
2 |
88 |
Indeck Energy Services and Ridgewood Power, SAPI |
Enacted |
|
Massachusetts |
1 |
188 |
American National Power, Indeck
|
Enacted |
|
New Mexico |
1 |
74 |
Williams Field Services |
Enacted |
|
New York |
2 |
158 |
CH Resources |
Order Issued |
|
Texas |
5 |
1,318 |
Dynergy Power, Calpine Corp. CSW Energy, Southern Energy |
Enacted |
|
West Virginia |
1 |
276 |
Allegheny Power |
Ongoing Investigation |
|
Wisconsin |
1 |
53 |
Mid-America Power |
Ongoing Investigation |
|
TOTAL |
31 |
13,349 MW
|
|
|
1Source: Merchant Power Scoreboard
2Source: Energy Information Administration
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Appendix C
Merchant Plants Under Construction or Under Development1
|
State
|
Number of merchant plants
|
Total MW
|
Parent Company
|
Status of Retail Restructuring Legislation2
|
|
California |
4
|
2,758 |
US Generating, Constellation Energy, Enron Capital, Calpine Corp.
|
Enacted
|
|
Connecticut
|
2
|
882
|
Bridgeport Energy, US Generating
|
Enacted
|
|
Illinois
|
2
|
850
|
Dominion Energy/Peoples Energy,
Dynegy
|
Enacted |
|
Maine |
3 |
935 |
American National Power,
U.S. Generating
|
Enacted
|
|
Massachusetts
|
4
|
1,353
|
US Generating, Berkshire Power, Energy Management and Calpine, American National
Power
|
Enacted
|
|
Michigan
|
1
|
550
|
CMS Energy and DTE Energy
|
Order Issued
|
|
Mississippi
|
1
|
800
|
LS Power and Cogentrix |
Ongoing Investigation |
|
Missouri
|
1
|
250
|
Associated Electric Cooperative and Duke Energy
|
Order Pending
|
|
Nevada
|
1
|
480
|
Houston Industries and Sempra Corp.
|
Enacted
|
|
New Hampshire
|
1
|
15
|
Indeck
|
Enacted
|
|
Pennsylvania
|
2
|
155
|
PEI Power Corp, Williams Energy Group
|
Enacted
|
|
Rhode Island
|
1
|
265
|
Energy Management and Calpine
|
Enacted
|
|
Texas
|
8
|
5,293
|
Gregory Power, Tenaska, Occidental Energy Ventures, American National Power, Calpine
Corp
|
Enacted
|
|
Virginia
|
1
|
300
|
Commonwealth Chesapeake Corp.
|
Enacted
|
|
TOTAL
|
32
|
14,886 MW
|
|
|
1 Source: Merchant Power Scoreboard
2Source: Energy Information Administration
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Appendix D
Reported Plans for Merchant Plants1
|
State
|
Planned merchant plants
|
Total MW
|
Parent Company
|
Status of Retail Restructuring Legislation2
|
|
Alabama
|
1
|
100
|
Southeastern Electric Development
|
Ongoing Investigation
|
|
Arizona
|
2
|
1,100
|
PP&L Global, Inc., Calpine
|
Enacted
|
|
California
|
13
|
8,600
|
Summit Group International, Ogden Power, AES, Enron, Duke Energy, Power Development
Company
|
Enacted
|
|
Connecticut
|
4
|
2,284
|
Power Development Company and El Paso Energy, AES, PPL Global
|
Enacted
|
|
Florida
|
2
|
1,350
|
Duke Energy, Constellation Power
|
Ongoing Investigation
|
|
Georgia
|
3
|
1,380
|
Sonat Energy Services, Southern Company, Carolina Power & Light
|
Ongoing Investigation
|
|
Idaho
|
1
|
270
|
Cogentrix and Avista Power
|
Ongoing Investigation
|
|
Iowa or Illinois
|
1
|
600
|
Calenergy and Mid-American Energy
|
Ongoing Investigation (Iowa) Enacted (Illinois)
|
|
Illinois
|
4
|
2,484
|
Dynegy, KN Energy, LS Power, Houston Industries
|
Enacted
|
|
Indiana
|
2
|
550
|
LS Power, Primary Energy
|
Ongoing Investigation
|
|
Kentucky
|
2
|
500
|
Dynegy, Enron Capital & Trade Resources
|
Ongoing Investigation
|
|
Louisiana
|
1
|
11
|
Nations Energy
|
Ongoing Investigation
|
|
Maine
|
7
|
3,130
|
Alternative Energy, Champion International, American National Power, International
Power Partners, Indeck Energy Services, FPL Group, Industry and Energy Group
|
Enacted
|
|
Massachusetts
|
7
|
6,407
|
Infrastructure Development Corp, American National Power, US Generating, Constellation
Power, Southern Energy, Power Development Corp, Sithe Energy, Inc.
|
Enacted
|
|
Michigan
|
2
|
1,480
|
US Generating, Wyandotte Energy
|
Order Issued
|
|
Minnesota
|
1
|
362
|
NRG Energy and Tenaska
|
Ongoing Investigation
|
|
Mississippi
|
3
|
1,125
|
Enron
|
Ongoing Investigation
|
|
Missouri
|
1
|
250
|
Associated Electric Cooperative and Duke Energy
|
Order Pending
|
|
Montana
|
3
|
2,420
|
Composite Energy, Glacier International, Cogentrix
|
Enacted
|
|
Nevada
|
2
|
556
|
Biogen Partners, Coastal Power
|
Enacted
|
|
New Hampshire
|
3
|
1,925
|
AES and Conservation Law Foundation, Tractebel Power and Sprague Energy, Southern
Company
|
Enacted
|
|
New Jersey
|
2
|
1,900
|
US Generating
|
Enacted
|
|
New Mexico
|
2
|
600
|
Dynegy Power, QUIXX
|
Enacted
|
|
New York
|
5
|
4,080
|
US Generating, Megan-Racine Assoc., American National Power, Sithe Energies
|
Enacted
|
|
North Carolina
|
1
|
1,100
|
Carolina Power & Light
|
Ongoing Investigation
|
|
Ohio
|
3
|
1,149
|
Columbus Power Partners, Ohio National Energy, Duke Energy
|
Order Pending
|
|
Oklahoma
|
3
|
1,425
|
Associated Electric Coop and KAMO Power, Cogentrix and Power Resource Group, OGE
Energy
|
Enacted
|
|
Oregon
|
1
|
460
|
Hermistion Power Partners
|
Order Pending
|
|
Pennsylvania
|
3
|
1,800
|
Columbia Electric, PP&L Global, AES
|
Enacted
|
|
Rhode Island
|
2
|
1,250
|
Houston Industries, Tuspani Water Co.
|
Enacted
|
|
Tennessee
|
1
|
600
|
Enron
|
Ongoing Investigation
|
|
Texas
|
6
|
3,055
|
Tractebel Power, Dynegy, Panda Energy, Air Liquide America and Houston Industries,
US Generating
|
Enacted
|
|
Vermont
|
1
|
1,225
|
Vermont Energy Park Holdings
|
Order Issued
|
|
Washington
|
3
|
1,198
|
FPL Energy, National Energy Systems, US Generating
|
Ongoing Investigation
|
|
West Virginia
|
1
|
240
|
MCN Energy Group
|
Ongoing Investigation
|
|
Wisconsin
|
5
|
1,700
|
Mid-American Power, SkyGen, Polsky Energy, Southern Energy, Wisconsin Electric Power,
|
Ongoing Investigation
|
|
Wyoming
|
3
|
570
|
Black Hills Corp, North American Power Group, Zeigler Coal Holding
|
Ongoing Investigation
|
|
TOTAL
|
107
|
56,021 MW
|
|
|
1Source: Merchant Power Scoreboard and Energy Information Administration
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Appendix E
Proposed Characteristics of an RTO
At a minimum, an RTO must have the following characteristics:
1
- must be independent from market participants;
- has the appropriate scope and regional configuration;
- possesses the operational authority for all transmission facilities under its control;
and
- has exclusive authority to maintain short-term reliability.
In addition, an RTO must perform these minimum functions:
(2)
- administer its own tariff and employ a transmission pricing system that will promote
efficient use and expansion of transmission and generation facilities;
- create market mechanisms to manage transmission congestion;
- develop and implement procedures to address parallel path flow issues;
- serve as a supplier of last resort for all ancillary services required in Order
No. 888 and subsequent orders;
- operate a single OASIS site for all transmission facilities under its control with
responsibility for independently calculating its total transfer capability and available
transfer capability;
- monitor markets to identify design flaws and market power; and
- plan and coordinate necessary transmission additions and upgrades.
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Appendix F
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.
Midwest ISO
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.
California ISO
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)
ERCOT-Texas ISO
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.
- Merchant Power Scoreboard, www.mwbb.com/services/energy-mp.htm,
web site established by McGuire, Woods, Battle & Boothe
- 79 FERC 61,374
- 283 FERC 61,352
- 81 FERC 61,257
- 84 FERC 61,231
- 81 FERC 61,122
- Electricity Daily,
May 24, 1999.
- Public Utilities Commission of Texas, Order on ERCOT Independent
System Operator and Electronic Transmission Information Network. Project No. 16018.
August 22, 1996.
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