**DEFAULT SERVICE FOR RETAIL ELECTRIC COMPETITION:**

**CAN RESIDENTIAL AND LOW INCOME CUSTOMERS BE**

**PROTECTED WHEN THE EXPERIMENT GOES AWRY?**

Barbara R. Alexander

Consumer Affairs Consultant

83 Wedgewood Dr.

Winthrop, ME 04364

(207)395-4143

E-mail: <barbalex@ctel.net>

# APRIL 2002

Barbara R. Alexander opened her own consulting practice in March 1996.
From 1986-1996 she was the Director, Consumer Assistance Division, at
the Maine Public Utilities Commission. Her special area of expertise has
been the exploration of and recommendations for consumer protection,
universal service programs, service quality, and consumer education
policies to accompany the move to electric, natural gas, and telephone
competition. She authored "A Blueprint for Consumer Protection Issues in
Retail Electric Competition" (Office of Energy and Renewable Energy,
U.S. Department of Energy, October, 1998, available at
[http://www.eren.doe.gov/electricity_restructuring/toc.html]{.underline}.
Her clients include national consumer organizations, state public
utility commissions, and state public advocates.

This paper was originally published in April 2001 and updated in October
2001. This version reflects the most recent information available for
state activities with respect to Default Service through 2001 and early
2002. However, readers are cautioned that the states described in this
paper routinely consider changes to state restructuring policies that
have a significant impact on the nature, price, and purpose of Default
Service.

This report was prepared under contract with

Oak Ridge National Laboratory Energy Division

UT-Battelle, LLC

Subcontract No. 4000007935

The opinions and conclusions expressed in this report are

those of the author alone and do not represent

the views of Oak Ridge National Laboratory or the

U.S. Department of Energy

**INTRODUCTION**

The purpose of this paper is to summarize developments with respect to
Default Service for residential customers in key states that have moved
to retail electric competition and provide recommendations with regard
to this important policy for the near term. While every state has made
some provision for Default Service, the identity of the Default Service
provider and the pricing mechanism that governs this service has varied.
This report will highlight those states that have taken recent steps to
implement the policy decisions reflected in state electric restructuring
legislation, compare their experiences, and make some preliminary
observations about trends and impacts of these developments on
residential and low income customers in particular. This paper focuses
on the implications and policy considerations of Default Service for
residential customers and does not address equally important aspects of
Default Service for commercial and industrial customers.

[Definition of Default Service.]{.underline} This service is labeled
with different names ("Standard Offer"; "Provider of Last Resort";
"Basic Generation Service"), but in this report the term "Default
Service" will be used to identify the service that is made available to
any residential customer who chooses not to choose (or who affirmatively
chooses Default Service), who is unable to obtain competitive electric
service, whose competitive service is cancelled, or whose supplier is
unable to provide service. While some states have separated these
services, every state that has adopted electric restructuring has
provided for this type of service, which has been widely acknowledged as
essential to the transition to competitive markets. In reality, the lack
of Default Service, supplied automatically to any customer without a
competitive supplier of electricity, would mean that such customers
would be physically disconnected from the distribution system. Default
Service is viewed as a regulated service (even if priced pursuant to
market conditions) in every state and its price, and terms and
conditions are subject to regulation by the state regulator of electric
utilities. In most states, the price of this service is linked to rate
decreases or rate caps mandated by the restructuring legislation or a
utility-specific restructuring decision. While this service is provided
by means of or through the local distribution utility in most states,
other entities provide or will provide this service in some states.

[Importance of Default Service.]{.underline} This service has enormous
implications for lower use residential and small commercial customers
and low-income customers in particular. First, the political
acceptability for the concept of energy competition depends in part on a
smooth transition from the breakup of the vertically integrated monopoly
to a system in which part of the service (distribution and transmission)
is price-regulated and part (generation service) is subject to
competition with an unregulated price. Legislators and regulators in
most jurisdictions have concluded that customers will not tolerate
mandatory change (e.g., forced migration[^1] to the competitive market)
or widespread confusion about the continuation of their electric
service. Therefore, the concept of Default Service has been created as a
method of allowing customers to do nothing and continues to receive an
essential service at a regulated price, at least during a transition
period.

Second, policymakers have argued, successfully in many states, that
lower use customers are either not eager to enter the competitive market
or are unlikely to see lower prices, at least in the early days of the
development of the competitive market.[^2] As a result, a service is
required to ensure that such customers can continue to receive
electricity as an insurance that the market will not in fact "work" and
produce multiple suppliers with products that are likely to interest
most residential customers.

Third, consumer advocates have pushed primarily for rate caps or rate
decreases for residential customers and low-income program expansions
for low-income customers as the "price" for the move to retail
competition. This approach complements the desire for stability by
residential customers who may not be ready to jump into the competitive
market, but this approach also carries with it the implication that the
creation of a competitive market is less of a priority than providing
basic service at an affordable price.

Finally, low-income advocates have feared redlining and discriminatory
conduct by unregulated competitive providers for energy services and
expect that their clients will not be desirable customers. These
advocates often focus on the potential for adverse experiences in other
competitive markets, the trend evidenced in many markets to segment the
market, and the concern that low-income customers may be discriminated
against because of their lower usage and the assumption that such
customers are more likely to require more customer care in the form of
payment arrangements and collection activity.

Given these conflicting interests surrounding the need for the Default
Service mechanism, it is no wonder that the implementation of state
policy in this regard has been fraught with controversy and downright
intrigues. If you believe that the prime imperative that must govern the
decisions surrounding the implementation of retail competition is the
need to create a competitive market as fast as possible, Default Service
is a tool that should be wielded to achieve that end. For these
advocates, the market power of the incumbent utility should be broken up
at all costs. On the other hand, if you believe that the competitive
market is unlikely to develop in the near future or that when developed,
is likely to result in higher prices or less stable prices for
residential customers, Default Service is viewed as a tool to maintain
important consumer protections and the longstanding acceptance of the
universal service aspects of basic electricity service for residential
and low income customers. Both these conflicting approaches are
reflected in the state decisions examined in this report.

Whatever the motivations and decisions concerning Default Service, the
early experience in every state demonstrates clearly that this service
will provide electricity service to the vast majority of residential and
small commercial customers in the near future. This is because in most
states residential customers have not shopped or selected an alternative
provider or alternative providers have abandoned the market and focused
on larger commercial and industrial customers. Even in Pennsylvania
where the highest level of customer shopping has occurred, the
percentage of residential customers who are shopping has never exceeded
30% in any utility service territory and was less than 10% in most
utility areas.[^3] Whether this lack of shopping in other states is due
to lack of competitive marketing by suppliers, the economics of the
market, or the decisions of regulators that have favored incumbent
utilities, the fact remains that the Default Service decisions have been
the primary factor in determining the price and identity of the provider
of basic electric service for the overwhelming number of customers in
states that have implemented retail electric competition.

## 

## 

## MODELS FOR DEFAULT SERVICE

There are three basic models that the states have used to structure
Default Service. The key variables in all these models are (a) Who
provides the service?; (b) At what price?; and (c) For what group of
customers?.

1.  [Local Distribution Utility with Rate Cap or Rate
    Reduction]{.underline}: Under this approach the local distribution
    utility retains the obligation to provide Default Service to
    customers who choose not to choose and any other customer who
    affirmatively requests this service after entering the competitive
    market. This service is typically provided with rate caps or rate
    reductions for a period of time that often reflects the utility's
    right to recover stranded costs.[^4] Whether the local utility
    provides this service by means of retained generation assets,
    contracts for its obligation at specified prices that accompany the
    sale of such generation assets, or goes into the wholesale market
    for needed energy, the price is regulated (either as the total bill
    or as unbundled components of the total bill) and the utility has
    the obligation to serve. In states that have adopted this approach,
    the customer receives an unbundled bill from the utility in which
    generation service is presented in a manner that allows the customer
    to compare prices and shop for this competitive service. This model
    for Default Service is the most common and is currently in use in
    Pennsylvania, Ohio, Maryland, New Jersey, Delaware, Connecticut, New
    Hampshire, Virginia, and Michigan. A variation on this theme has
    been used in Massachusetts and Rhode Island, where the local
    distribution utilities remain responsible for the provision of
    Default Service, but this service is itself split between those
    customers who choose not to choose and who were served by the
    utility at the time of the implementation of retail competition
    (Standard Offer Service) and another group of customers who entered
    the competitive market and sought to return to the utility or who
    became customers after the implementation of retail competition
    (Default Service). While the local distribution utility is required
    to provide both services, the method used for pricing the two
    services are different. Another variation on this theme has been
    used in Texas where all customers were transferred from the
    vertically integrated local utility to the retail sales affiliate of
    the utility at the onset of retail competition. However the price
    that this retail affiliate must provide service is regulated ("Price
    to Beat") for a period of years, with a rate reduction of at least
    6% compared to pre-competition rates. Under this approach, the
    identity of the Default Service provider has been changed compared
    to the prior utility, but the rates remain regulated. However, the
    Texas model[^5] is unique in that the Price to Beat utility is not
    the automatic provider of service to all customers. While most
    customers can move in and out of Price to Beat service during the
    transition period, some customers are automatically transferred to a
    separate Provider of Last Resort that has been established to
    provide service to customers whose supplier defaults or customers
    who are terminated by the retail supplier (e.g., termination of
    contract for nonpayment). The price for Provider of Last Resort
    service reflects the result of a competitive bid that is likely to
    mimic short-term wholesale market prices.

2.  [Competitive Bidding for Retail Generation Portion of Utility
    Bill:]{.underline} Under this approach the state has mandated that
    the price for Default Service must be established by means of a
    competitive bid to provide retail generation services. In some
    states, such as Maine, the state regulatory commission conducts the
    competitive bidding and awards the bid directly. The most recent
    round of bidding for residential customers in Maine was awarded in
    late 2001 for a 2-3 year period at fixed rates that were only
    slightly in excess of current rates or, in the case of one utility,
    significantly lower. In other states, such as Pennsylvania (for a
    percentage of the customer load), the utility conducts the bidding
    pursuant to regulatory supervision. In effect, this approach
    requires the local distribution utility to obtain the necessary
    generation to provide Default Service from retail competitive
    providers and reflect the identity of the provider on the utility
    bill. The major issue with respect to this type of approach is
    whether the "winner" gets to provide merely generation services (as
    reflected on the customer's bill issued by the local distribution
    utility) or can obtain the entire retail billing and collection
    relationship with the customer. The restructuring settlements for
    several Pennsylvania utilities contemplated obtaining a portion of
    the utility's Default Service load by means of competitive bidding
    for generation service, as well as billing and collection of the
    entire bill. However, this approach was not successful due to the
    requirement that such service be offered at rates equal or below the
    rate caps imposed on the utilities. PECO Energy finally obtained a
    bid from New Power to provide generation service only (via the
    utility-issued bill) for over 200,000 customers, but even this
    experiment has failed since the default of New Power and the return
    of these customers back to PECO Energy.

3.  [Pass Through of Spot Wholesale Market Price:]{.underline} This
    model for Default Service requires the utility to provide service,
    but it is priced by means of a pass through mechanism that reflects
    short-term (i.e., less than six months or spot market) prices on the
    wholesale market. There is no retail provider of electricity
    specifically identified on the customer's bill. Rather, this
    approach is closely linked with the desire to pass through "real
    time" wholesale market prices to retail customers. The utility is
    typically obligated to obtain this service through a transparent
    mechanism, such as a bid or purchase of electricity at spot market
    prices. The intent of this approach, according to its proponents, is
    that customers will see the "true" cost of electricity and make
    purchasing and usage decisions that will result in overall lower
    prices in the long run. However, the short-term results due to the
    use of this approach has exposed residential and small commercial
    customers to volatile prices and overall higher prices compared to
    pre-competition utility service. This approach is used in
    Massachusetts to price the Default Service that is applicable to
    customers who return to the local utility or who are not otherwise
    eligible for the Standard Offer Service. Consolidated Edison in New
    York also uses this method to price Default Service to all
    customers. This approach has been the most controversial means for
    pricing Default Service.

**OBSERVATIONS**

It is possible to summarize developments that have occurred to date in
the various state models that are explored in more detail in this
Report. These observations reflect state experiences that reflect one or
more aspects of the three models identified above:

-   Most residential customers have not seen any significant change in
    prices since the onset of retail electric competition in most
    states. This is due to two developments. First, most states
    "anointed" the local utility to provide Default Service at rates
    that reflect the same prices that were in effect just prior to
    restructuring or at slightly lower overall rates. Second, the
    competitive market for residential customers has not developed as
    many initial proponents had suggested. Only a small minority of
    residential customers has chosen an alternative provider for
    generation service in any state and many generation providers have
    halted their initial forays into the mass market for the retail sale
    of electricity, concentrating instead on commercial and industrial
    customers. As a result, few customers have left Default Service and
    even if customers wanted to do so, there are few marketers (and in
    many states, no marketers) offering electric service at lower
    prices.

-   Low-income customers (typically defined as those with household
    income below 150-175% of federal poverty guidelines or who are
    already enrolled in state or federal financial assistance programs)
    have seen an increase in the availability of programs that offer
    rate discounts or percentage of income payment plans, as well as
    energy efficiency and weatherization programs. This is because the
    adoption of electric restructuring legislation was accompanied by
    increased funding for universal service programs in some states or,
    in other states, the creation of new programs funded by other
    ratepayers.

-   However, it is not clear how long residential customers can rely on
    the current prices for Default Service and universal service
    programs to provide a safety net when electric restructuring enters
    the post-transition phase. Those states that have relied on
    statutory or regulatory price caps and rate reductions for
    residential customers have yet to confront how to transition from
    these price protections to other mechanisms when the transition
    period is over. In some cases, the decisions are being deferred and
    in other cases, the transition period is being lengthened.

-   Suppliers and some policymakers in several states have pointed to
    price protections associated with Default Service as the reason for
    the lack of the development of the competitive market, suggesting
    that it may be difficult to retain price protection in the future.
    Other policy makers express frustration with the promises and actual
    results delivered due to retail electric competition and wonder how
    to "undo" deregulation. According to John Harwood, speaker of the
    Rhode Island House of Representatives, "Here we are five years
    later, and the rates are going up in the air on us. We felt there
    would be more competition and lower prices--but instead we have no
    competition and higher prices."[^6]

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-   Even where prices have been allowed to rise to reflect short term
    wholesale market rates, robust competition for residential customers
    has not emerged.

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-   States have typically structured Default Service to resemble the
    pre-restructuring rate design that was used by the local utility. In
    other words, states have unbundled transmission, distribution, and
    generation charges in a manner that preserves the historical rate
    design. This has left intact the inter- and intra-class allocations
    of responsibility for the utility's distribution revenue
    requirement. Some utilities have proposed changes in rate design to
    shift recovery of the distribution portion of the bill from
    usage-based charges to fixed monthly customer charges, i.e.,
    increasing the minimum monthly charge and reducing the amount of the
    distribution revenue requirement collected via kWh charges. However,
    such an approach would shift costs to lower use customers and result
    in higher monthly bills in most cases for lower use customers.

-   Default Service is typically accompanied by the traditional utility
    terms of service and consumer protections, such as the regulations
    that apply to the application for service, billing and billing
    dispute procedures, termination of service protections, the right to
    payment arrangements, medical emergencies and severe weather
    disconnection moratoria. Therefore, in most cases, there has been no
    sanctioned degradation of service quality or consumer protection as
    a result of the move to retail competition for customers on Default
    Service. It is not clear whether this linkage can be maintained in
    the future if non-utility providers seek to provide this service and
    bill and collect for both regulated and unregulated charges.

-   As long as there are a substantial number of residential customers
    receiving Default Service for any reason, the higher costs
    associated with serving those customers who need more attention in
    the form of payment arrangements, medical emergencies, and
    additional customer service will be spread among all residential
    customers or included in distribution (regulated) utility rates.
    This was the universal approach to residential customer rates and
    class rate design prior to restructuring. This approach may not be
    tenable in the future if a competitive market does develop and most
    residential customers enter the competitive market, leaving those
    with credit challenges or poor payment history behind.

-   If Default Service is limited or designed to serve an isolated group
    of credit challenged customers or those who have been terminated by
    competitive suppliers, it is likely that the price for this service
    will be higher than competitive prices offered to other residential
    customers and higher than current traditional utility rates that
    reflect averaged costs for residential customers.

-   Those states that have relied on short term wholesale market prices
    for Default Service in any form (not the typical state approach, but
    reflected in the competition programs in New York (Consolidated
    Edison), Massachusetts, and Texas (for POLR customers)) have been
    unable to provide this service without significant price volatility
    and overall price increases compared to Default Service available to
    programs in other states. This has occurred even though the affected
    customers typically do not have the ability to "respond" to these
    price signals by using alternative fuels or relying on sophisticated
    metering technology to ameliorate high price periods.

-   Low-income customers are clearly more at risk in a system that
    adopts the Texas POLR model because this approach focuses on those
    that drop out of the competitive market and does not link this
    smaller group to the larger pool of residential customers who do not
    shop for electricity in the competitive market.

-   There is no evidence as yet that any competitive supplier can or
    seeks to provide service to residential customers at the embedded
    costs reflected in current rates charged by most utilities for
    generation service when it is linked to billing, metering, and
    customer care services. The use of a competitive bid to obtain
    generation service, while theoretically appealing because it results
    in the entry of a competitive supplier with little or no acquisition
    costs, has not generally been successful. As a result of attempts to
    bid out Default Service in Pennsylvania, it appears that the
    provision of retail Default Service with the full panoply of
    consumer protections embedded in the current utility practices and
    procedures are not easily duplicated or capable of being replicated
    for the unbundled price of generation and billing services being
    offered by incumbent utilities.

-   Some commenters have urged states to adopt Default Service policies
    that will pass through market based rates even during the market
    development period and argue that customers must experience as close
    to real time pricing as possible in order for a genuine competitive
    market to development. For example, the National Energy Marketers
    Association (NEMA)[^7] points to the role of the incumbent in the
    provision of Default Service as a significant impediment to the
    ability of competitive providers to enter the mass market. NEMA
    recommends that default service be awarded based on price bids
    supervised by the state commission and the price for this service
    should "account for changing market conditions."[^8] Others have
    argued that the lack of "price signals" in rates that are fixed and
    capped to avoid the volatility of the wholesale market contribute to
    higher prices in the long run and slows down the development of a
    competitive market. FERC has noted, "\[L\]ack of price-responsive
    demand is a major impediment to the competitiveness of electricity
    markets." Also, "The fact that retail customers had no incentive to
    adjust their usage based on price contributed to the price
    spike."[^9]

-   Clearly, there is a growing disconnection between the promises that
    state legislators and regulators initially presented as their basis
    for the move to retail competition and the actual events that have
    occurred or not occurred in the last 4-5 years. As a result, states
    and state regulators in states that have restructured may be
    pressured to ease up on promises of lower rates to mass market
    customers and roll back or "reinterpret" rate caps and rate freezes.

-   The use of municipal aggregation to provide a stable price for
    residential customers is still viewed favorably by consumer
    advocates, but the only place in which this approach is being used
    on a large scale is in Ohio. Even this approach, however, may be
    successful only because of its reliance on the terms of utility
    restructuring settlements that offered a certain percentage of the
    utility's generation to alternative suppliers at low prices. The
    Cape Electric Compact in Massachusetts has not been able to obtain
    rate quotes that are less than Standard Offer Service provided by
    the local utility, but a proposal to allow the Compact to provide
    Default Service at lower rates than that service is provided by the
    local utility is moving forward. Any successful use of municipal
    aggregation appears to require the use of the "opt out" approach or
    negative option approach to assure sufficient volume of customers to
    interest bids by competitive suppliers.

-   The risk of price volatility is increased by the infancy of the
    wholesale market and the uncertainty associated with the role of
    FERC and the emerging regional transmission organizations. Whether
    these initiatives will result in more or less price stability is not
    clear, but state consumer advocates remain concerned about the
    "federalization"[^10] of the pricing of electricity sold to retail
    customers, particularly in light of FERC's failure to control spot
    market gaming and the exercise of market power in certain regional
    markets and the agency's perceived inability to correct market-based
    rates even when it finds they are unreasonable.

-   There is no evidence that Congress will mandate retail electric
    competition at the state level. As a result, Default Service
    policies will remain in the hands of the various states. However,
    because of the importance of the operation of the wholesale market
    in the delivery of retail prices to Default Service customers, the
    move to retail competition has transferred the power to set rates
    for retail customers from the state regulators to FERC. When
    generation is no longer owned by the utility that has a state
    franchise and obligation to serve and must obtain energy for its
    customers in the wholesale market under FERC's jurisdiction, state
    regulators may lose the ability to ameliorate price spikes or
    supervise plant investment and return on that investment. Only FERC
    has the authority under the Federal Power Act to assure "just and
    reasonable rates" in the wholesale market. The transfer of authority
    from the restructuring states to FERC in the development of a
    competitive electricity market will have significant impacts on
    residential and low-income customers who are captives of the Default
    Service provider.

-   In contrast to those who seek more price volatility and market-based
    rates for Default Service, many states have pulled back, delayed or
    outright rejected the move to retail competition. Such states
    include Nevada, New Mexico, Arizona, Oklahoma, Montana, Oregon,
    Arkansas, North Carolina, Iowa, and Minnesota. California, the
    originator of retail competition, has ended retail electric
    competition by statute.

**RECOMMENDATIONS**

If short term wholesale market prices are likely to reflect volatile
prices and the uncertainty associated with new institutions and market
forces that are not entirely understood, what should states do with
respect to Default Service? Should states adopt different pricing
methodologies to allow market forces to be reflected in residential
customer rates? If so, should these rates be structured to reflect the
short-term market prices or a fixed and stable price that reflects
long-term prices? Should states allow payment-troubled customers to be
charged higher rates to maintain or obtain electric service? Should
Default Service be tied to lesser consumer protections or more targeted
benefit programs? Finally, should Default Service be designed to further
the development of the competitive market and at what cost?

The answers to these questions will be very different depending on the
policymaker's views of the purpose of Default Service.

-   **Full Speed Ahead.** If Default Service is intended to be a bridge
    to a competitive market, then the service will be designed to
    stimulate the entry of retail marketers and its pricing method will
    tend to "drive" customers into the arms of marketers. It is this
    approach that typically results in proposals to pass through
    short-term market prices or that seek to increase prices for Default
    Service to make it possible for marketers to offer lower prices to
    Default Service customers or offer products to avoid the volatility
    of Default Service.

-   **Go Slow.** Alternatively, Default Service could act as a benchmark
    to assure that competition will offer as good or better service at
    better prices than delivered by traditional regulation or as a hedge
    in case the competitive market does not develop in a timely way or
    the wholesale market does not mature. Under this approach, Default
    Service will be designed to assure stable and affordable prices for
    customers who do not shop or who are not the subject of offers by
    mass market retail providers. In this viewpoint, the competitive
    market will woo customers by offering either a product that is not
    otherwise available ("green" energy; time-of-use meters; bundled
    products) or a basic product that is in fact cheaper than the more
    traditionally priced electric service.

Proponents of the "full speed ahead" approach to Default Service have
lost some steam in the last year with the collapse of the California
market, the decimation of the numbers of competitive marketers that
focus on residential customers, the scandals associated with the Enron
Corporation who was the leading proponent of retail energy competition
in every state, the volatility of the wholesale market where that market
has been used as the basis for residential energy prices, the failure of
FERC to react promptly to numerous allegations of market failure, and
the failure of the competitive bidding approach for Default Service in
Pennsylvania. These same developments have stimulated consumer advocates
to focus on the "go slow" or "go slower" approach.

Based on the individual state experiences and the events that have
accompanied the first several years of full-scale electric competition,
I recommend the following key ingredients for Default Service policy:

1.  **Default service should be designed as a stable and quiet haven for
    residential customers on the assumption that the development of a
    retail competitive market might take longer than** **originally
    contemplated and might result in upheavals in the early stages of
    its development**. This service should not "drive" customers to a
    competitive market that may experience volatile prices or the
    exercise of unlawful market power, particularly when the design and
    operation of the wholesale market is in a stage of infancy and over
    which state regulators have little control.

2.  **Default Service should be designed for a lengthy period of time**
    and reflect stable and fixed prices that are established to reflect
    a mix of generation assets and time periods.

3.  **Default Service should be structured and disclosed on customer
    bills as "price to compare"** so that customers can shop and compare
    this service to offers from competitive marketers. Marketers faced
    with this approach to Default Service will be able to structure
    their business models and marketing programs to reflect a known
    target.

4.  **Default Service should be designed to provide rates to the full
    range of residential customers who do not shop, who enter and then
    leave the competitive market, or who are customers of competitive
    provider who choose to leave the competitive market**. Those who may
    be "left behind" in a competitive market, such as rural, low-income,
    payment troubled, or credit challenged customers, should not be
    isolated in the provision of this service.

5.  **Default Service should be billed and collected by incumbent
    utilities because there is no evidence that competitive providers
    can provide these services at less than current prices. However, the
    state regulatory authority may wish to consider regularly bidding
    out the generation portion of this service to creditworthy
    competitive providers under a stated rate cap or set of rate
    regulations that assure long-term stable prices.** The ability to
    compete for this service should be an indication of the competitive
    market's ability to provide stable and reasonably priced service to
    mass market customers. Over time the state authority may also want
    to explore the potential of competitive billing for this service,
    but only after competitive providers have demonstrated the ability
    to provide this service with the same or lower cost and reflective
    of the current service quality and consumer protections provided by
    incumbent utilities.

6.  **Default Service should be provided with the same consumer
    protection rules applicable to incumbent utilities**. The provider
    of this regulated service should be empowered to use the collection
    tool of disconnection of service.

7.  **Default Service should not be accompanied by switching fees or
    surcharges that would discourage customers from freely moving in and
    out of the competitive market.**

8.  **Low income customers should not be restricted in their ability to
    move in and out of the competitive market, but rather should be
    allowed to carry any bill payment assistance programs for which they
    qualify to competitive providers**. While states may want to explore
    the use of aggregation to obtain lower cost energy for customers who
    receive bill payment assistance benefits, such approaches should not
    link the receipt of benefits to the aggregator's energy service.

9.  **In the long run, policymakers in the restructuring states may need
    to devise a Default Service that reflects the development of a
    robust retail market in which competitive marketers are serving the
    vast majority of residential customers. Under this scenario, Default
    Service may be equivalent to a "fail safe" service used primarily by
    those who either move in and out quickly or those who are unable to
    obtain service from other marketers (low usage, payment troubled or
    credit challenged customers).** This scenario does not need to be
    addressed at this time because it is unlikely to occur due the lack
    of development of the retail market. However, it is not too early to
    establish the basic principle that retail electric competition
    should not deaverage rates to create a new class of residential
    "losers" as the price for the development of competition. Consumer
    advocates should seek legislative and policy commitments that
    reflect the need to provide affordable electricity for all
    residential customers. This commitment will require more than the
    creation and funding of a targeted "low income" program for several
    reasons. First, such programs are rarely sufficient in scope or
    funding to meet actual needs. This is particularly true for those
    families with incomes slightly above the poverty guidelines. Second,
    due to flawed program design, inefficient enrollment techniques, and
    the rapid turnover of the low-income population, the penetration
    rate for these programs is usually significantly less than the
    eligible population. Third, there is no net benefit in providing a
    new subsidy (e.g., a discount in the monthly customer charge) that
    is less than the increased price for electric service (such as those
    passed through to Consolidated Edison's residential customers last
    year) that results from a volatile energy market. Rather, this
    commitment to affordable service is likely to require consideration
    of a Default Service price support mechanism that is reflected in
    the rates of all other customers.

**STATE SUMMARIES**

**California.** Although it was the first state to move to retail
electric competition, California established a market structure and
pricing mechanism for Default Service that has not been copied by other
states. California=s restructuring statute,[^11] enacted in 1996,
required incumbent utilities to serve any customer as a default provider
and mandated a 10% rate reduction to accompany the move to competition.
Actual full-scale retail competition began in March 1998. As of that
date, utilities were required to sell all the power they owned and buy
needed power for Default Service from the Power Exchange utilizing the
spot market until the end of the transition period, April 2002, at which
time stranded cost recovery was to be completed. A separate
organization, the California Independent System Operator (ISO) was given
control of the transmission system and required to maintain the safety
and reliability of the electric system, as well as the obligation to buy
sufficient power to balance the power needs of the system.

The Commission required that utilities pass through the wholesale price
of electricity as reflected in the Power Exchange rate to their
customers. This rate was calculated weekly based on hourly price changes
and so the price for this service varied every month and was subject to
more significant variation between the summer and winter months. During
the transition period when utilities were supposed to be collecting
stranded costs, this volatility was masked in part by a mandated 10%
rate reduction. In other words, no matter what the price of the power
bought by the utility from the Power Exchange, the resulting total bill
had to be 10% lower during the transition period. The initial rate
reduction was funded by securitization of the utility's stranded costs.
It was expected that stranded costs would be paid off by the end of the
transition period, thus opening up the market to seek customers by
offering lower bills than reflected in the 1998 rates. In other words,
this feature of the California restructuring plan in which customers
were to see rate reductions, but that utilities were to obtain most of
the Default Service power from the wholesale market, was fully
understood by policymakers and utilities from the onset of
restructuring.

Universal service and energy efficiency programs were also explicitly
approved as part of the move to retail electric competition and the
long-standing tradition for including the costs of these programs in the
rates paid by all customers was continued with the Legislative
endorsement of the 15% rate discount at each electric and natural gas
utility through the California Alternative Rates for Energy (CARE)
program. This discount is calculated based on the total bill, including
energy.

After the implementation of competition, a residential Default Service
customer in California[^12] received a monthly bill that stated the
unbundled energy costs and then broke down the total electricity charge
into the following components:

-   CTC (Competitive Transition Cost) Charge (stranded costs)

-   PX Energy Charge: AThe Average PX charge is based upon the weighted
    average costs for purchases through the Power exchange. This service
    is subject to competition. You may purchase electricity from another
    supplier.@ The customer is informed of this charge on their bill,
    that is, the average PX charge per kWh during the billing period.

-   Transmission Charges

-   Distribution Charges

-   Nuclear Decommissioning Charges

-   Public Purpose Program Charges

-   Trust Transfer Amount (securitization of stranded costs and the
    mandated rate reduction)

-   Other Charges

If a customer shopped for electricity and selected a competitive
provider, the bill would be calculated as if the customer was a bundled
service customer and then show a credit for the amount of the PX price
for that month. In other words, in order to compete with Default
Service, the supplier had to sell generation service at a retail price
than was less than the wholesale spot market price passed through by the
utility. This exercise was made in even more difficult for the supplier
because the utility=s PX charges varied every month to reflect the
market wholesale price, but the volatility was masked by the overall 10%
rate reduction. As a result, competitive providers were not able to
market the sale of generation in a manner that allowed a customer to
compare the price of generation that appears on the utility=s monthly
bill. No matter what price was stated for PX Energy on the customer=s
bill, the total bill reflected a 10% rate decrease during the transition
period. The reason why most suppliers early on decided that they could
not compete in the residential market in California is not hard to
determine in light of this approach.

The legislation intended that the rate reduction would disappear when
the utility had paid off its stranded costs. This was expected to occur
no later than April 2002. At that point, the actual monthly PX price
would appear on the customer=s bill. The Commission was forced to
confront the consumer implications of passing through the variable PX
price for energy sooner than expected, however, when one utility paid
off its stranded costs earlier than projected. In early 1999, San Diego
Gas and Electric obtained PUC approval to end the 10% rate decrease and
begin billing that actual PX Energy charge. On an annual basis, both the
Commission and the utility expected that customer=s total bill would
decrease.[^13] However, the potential volatility associated with the
"normal" seasonal increase in the PX wholesale price during the summer
months was addressed by putting a cap of 12.5% on the increase
associated with any summer electric bill (July, August, September). If
the total bill would otherwise increase by more than this amount due to
the PX energy prices, SDG&E was authorized to collect the difference
from its customers in future bills, thus attempting to levelize the
expected modest seasonal volatility in rates.

The Commission strongly supported the notion of Aaccurate price signals@
in a related decision: A Only through accurate price signals can
customers understand how their usage impacts the system and make
economically efficient choices. The price of electricity fluctuates;
thus far, consumers have not been impacted by these fluctuations.
Consumers should have the opportunity to respond to such market signals
as they see fit, which may include shifting load, conserving power, or
procuring the commodity through direct access. As the market evolves, we
would expect ESPs to offer products and services that will allow greater
means to smooth bills.@[^14] Of course, all electric utilities were
required to continue offering budget payment plans.

These assumptions about annual customer savings were proven wrong when
in May 2000 PX energy rates began to increase dramatically. Bills for
SDG&E customers increased 200-400% during the summer of 2000. While
customers were paying 3.5 cents per kWh for the generation portion of
the bill prior to the end of the transition rate reduction, they were
facing charges as high as 20 cents per kWh by mid-summer.

While SDG&E passed through these high wholesale power prices to their
customers, other electric utilities had to pay the same higher costs for
this wholesale power, but were unable to pass through these charges to
customers because they were still subject to the 10% rate reduction
(Southern California Edison, Pacific Gas & Electric). Nonetheless,
because of the structure of the California electric market, these
utilities had to continue buying power through the PX. Throughout the
summer and fall of 2000, the rising wholesale power costs and resulting
high bills for San Diego customers and shockingly high power costs that
could not be recovered from customers imposed on the other two utilities
rapidly resulted in a "crisis.@ Utilities and state officials sought
intervention by the Federal Energy Regulatory Commission (FERC) to
establish caps on rates for wholesale power. Average prices in the
wholesale market were four to five times the prices of a year earlier,
and three to four times the level that the utility could charge
customers. The shortfall for PG&E and SCE was approximately \$5 billion
by late fall. However, the assumption that the high prices would
ameliorate with the onset of winter proved false and the deficits
continued to mount.

The California Legislature and the Commission reacted to the SDG&E bills
by enacting a rate freeze, retroactive to June 1, 2000. Under this rate
freeze, the utility cannot charge a residential customer more than 6.5
cents per kWh for the generation portion of the bill through December
2002, which is still a substantial increase, compared to rates charged
in 1999. The excess costs incurred by SDG&E are being carried in a
balancing account for later rate treatment. In addition, on August 24,
2000, President Clinton released \$2.6 million for additional fuel
assistance in the San Diego area.

By the end of 2000, both PG&E and SCE were facing junk bond ratings for
their securities and the refusal of some generators to sell power to the
utilities because of their fear of nonpayment. Public discussion of
bankruptcy was widespread. In December, wholesale power rates hit \$600
per megawatt hour, compared to \$120 in June and \$22 at the time
deregulation went into effect in March 1998. Power costs for November
and December alone, exceeded the total cost for all of 1999 by 28%. In
mid- January 2001, rolling blackouts hit the northern part of
California, including parts of downtown San Francisco. Southern
California Edison announced a workforce reduction of 1,850 jobs in the
December, 2000-January, 2001 period. Reduced expenditures for operations
and maintenance were put into place totaling \$465 million.

As a result of these financial emergencies, both PG&E and SCE filed for
permission to halt the transition phase, end the 10% rate reduction, and
allow them to pass through the actual PX prices. In reaction to the
financial emergency facing PG&E and SCE, the PUC authorized temporary
rate increases for all PG&E and SCE customers, with an average 9%
increase for residential customers, effective January 2001.[^15] Also,
as a short-term measure to allow power to keep flowing, the California
Legislature authorized the State Department of Water Resources (DWR) to
buy electricity on behalf of the utilities. Beginning in January 2001,
the DWR spent about \$50 million per day to buy power for the utility
customers and initiated negotiations to buy power under long-term power
contracts with generators directly. In early February, the Legislature
enacted an even more sweeping measure that guaranteed that the State
will provide the major role in the purchasing of electricity for many
years. Under this legislation[^16], the State was authorized to enter
into long-term power contracts and pay for the energy by means of
revenue bonds that will be reflected in all customer bills. As a result,
the DWR will sell power to retail customers and use the utilities to
bill and collect on behalf of the State. Meanwhile, the two utilities
owe generators \$12 billion and have defaulted on payments for power
bought several months ago. Finally, in March 2001, the PUC approved
another round of rate increases for SCE and PG&E that are targeted to
customers who use 130% or more of their baseline electricity level.[^17]

Many observers have identified the key factors that have given rise to
this crisis:

-   increased electricity demand;

-   lack of adequate generation supply;

-   a poorly designed market structure (the creation and duties of the
    ISO and PX are unique to California);

-   the impact of rising natural gas prices throughout the country, thus
    causing increased costs to operate some generating facilities;

-   manipulation of the market by the generators who bought the plants
    previously owned by the utilities (Enron, Dynergy, Duke Energy,
    Reliant Energy, and Southern Company);

-   mismanagement by the utilities who could have obtained fixed price
    contracts in the fall of 2000 and refused to do so, thus taking
    their changes with the volatility of the wholesale market; or

-   simply bad luck (i.e., lower rainfall in the Pacific northwest).

These reasons will be the subject of vociferous arguments by others.
Unfortunately, the final result is likely to include higher rates for
electricity for all customers.

In addition to the adverse impact in California, the volatile wholesale
market has had a negative effect on other states, notably Oregon,
Washington, and Montana. The adverse impact on Oregon and Washington has
occurred even though those states have not adopted retail electric
competition because utilities in those states must enter the wholesale
market to buy power for their customers, only to find high prices,
reflecting the market needs of California consumers, as well as the
rapid growth in demand in their own regions. A number of publicly owned
or municipal utilities in the Pacific Northwest implemented significant
rate increases in 2001.

The impact in Montana is particularly adverse. Montana adopted retail
electric competition in 1997.[^18] Larger customers, who had pushed for
the legislation, were able to shop for competitively priced electricity
before residential customers. Many large industrial and commercial
customers entered into contracts for electricity with prices linked to
wholesale market rates. The price charged for electricity took a
substantial jump in the summer of 2000, mirroring the California market.
Many factories, refineries and mining companies have temporarily shut
down or reduced employment as a result of soaring power costs. A survey
of industrial customers in Montana in early 2001 revealed that higher
electricity prices will force more than half of Montana=s largest
manufacturers to make major business changes in the upcoming year. Since
the summer of 2001, electricity rates in Montana have increased
tenfold.[^19] As a result of these developments, the move to retail
competition for residential customers has been halted and the Commission
has attempted to force the local distribution utilities to assume an
obligation to serve at regulated rates.

While California continues to pay a heavy price for its flawed and
failed scheme to achieve retail electric competition, significant
strides have been made to expand the benefits provided to low income
customers and significant efforts undertaken to expand participation in
these programs.

When the Commission adopted the 3 cents per kWh increase in May 2001 it
also exempted those customers with usage below 130% of the "baseline"
usage amount and all low-income customers on CARE rates (no matter their
usage level). The purpose of this rate increase was to pay for the
electricity being purchased by the Department of Water Resources (DWR)
on behalf of the electric utilities. This increase in revenue (about \$5
billion annually) was in addition to the \$1.5 billion rate increase
approved by the Commission in January. The new residential customer
rates increased kWh prices from 13-15 cents to 20-25 cents, depending on
the usage pattern in excess of the 130% baseline level.[^20]

At the same time the Commission ordered a Rapid Deployment[^21] of low
income programs, increased eligibility from 150% of federal poverty
income guidelines (PIG) to 175% PIG for the rate discount (CARE) and
energy efficiency program (LIEE), and increased the amount of the CARE
discount from 15% to 20% of the total electric bill. The Commission drew
on additional funding provided by new legislation to focus \$100 million
on paying for CARE discounts and increasing enrollment in the CARE
program.

The Rapid Deployment for CARE and LIEE ordered by the PUC has had modest
success. While enrollment has increased at all utilities, PG&E continues
to lag far behind SCE and SDE&G in its penetration rate. While
community-based organizations can contract with utilities to receive a
"capitation fee" for an enrollment of a qualified customer in CARE, a
relatively modest number of successful enrollments have occurred as a
result of this approach.

In comments to the PUC (and endorsed by other low-income advocates),
AARP[^22] has proposed that the Commission adopt a more efficient
approach for CARE enrollment, namely:

The current CARE application process requires the applicant to complete
and sign an application form. This approach is administratively unwieldy
and expensive when the applicant's income and assets have already been
evaluated for participation in well-established federal and state
low-income programs. The current process is also unlikely to enroll all
potentially eligible low-income customers because the additional utility
application process poses a "barrier to entry" that can easily be
removed without increase in program costs. Furthermore, the current CARE
application allows self-declaration based on a confusing definition of
"gross household income" that is likely to be misunderstood by many
customers.

The current CARE eligibility criteria are not typically used by other
states because many utilities and state commissions rely on categorical
eligibility to qualify or enroll customers in utility discount or bill
payment assistance programs.

The PUC should adopt a definition of "household" and "income" for CARE
that allows for categorical eligibility with Food Stamps, TANF or
CalWORKs, Medicaid or Medi-Cal, SSI, and LIHEAP. The distinctions
between CARE's household income calculations and those in effect for
these other programs are not necessary or meaningful considering the
scope and size of the CARE program and the need to foster enrollment of
low income customers in the face of the current energy crisis.

The Commission should take a leadership role to contact and encourage
the relevant California assistance agencies to design and implement a
negative option mailing to all current beneficiaries of the named
assistance programs. The recipients of the mailing should be informed
about CARE and their eligibility for this program, as well as provided
with a manner in which to decline enrollment if they so choose. After a
reasonable time, the name and address of all remaining individuals
should be transmitted to the natural gas and electric utility served by
that individual for enrollment in CARE. The Commission should order the
utilities and Energy Division, assisted by interested parties, to
coordinate with the Commission's efforts to work with other California
assistance agencies in the implementation of this project.

The Commission has yet to rule on any changes to the CARE application
process.

M**assachusetts.** The Massachusetts restructuring statute[^23] creates
two services: "Standard Offer Service" (SOS) and "Default Service."[^24]
Standard Offer service is provided by existing utilities to all
customers who choose not to choose and it is through this vehicle that
the statutory mandate for rate reductions (10% in year one and 15%
beginning on September 1, 1999) was reflected. Standard Offer service is
only available for the transition period of seven years (until March 1,
2005). The Act provides a limited set of circumstances under which a
customer may enter the competitive market and then return to this
service, but basically new customers who move into a distribution
utility=s service territory after competition begins or who seek to
return to regulated rates after swimming in the competitive waters are
not able to receive SOS. Customers who were being served by utilities in
March 1998 may enter the competitive market and return once within 120
days, but otherwise customers who enter the competitive market are not
otherwise eligible for Standard Offer Service. However, pursuant to
statute, low-income customers (defined as those receiving the low income
rate discounts available at each utility) can return to Standard Offer
service at any time.

Default Service is available for those customers who move into the
service territory after the onset of competition and those who wish to
return to regulated service after entering the competitive market. As of
late 2000, more than 500,000 residential customers were Aqualified@ for
Default Service pricing, primarily because they had moved to a new
location since March 1, 1998. Unlike SOS, however, Default Service is
required by the legislation to reflect "market based rates" and is not
subject to the rate caps or rate reductions associated with SOS. Because
it was not clear how this term should be implemented, the Massachusetts
Department of Energy and Telecommunications (DTE) decided early on that
until the mechanisms for procuring and pricing Default Service could be
fully implemented, utilities should provide those eligible for Default
Service with the Standard Offer price.[^25] However, the DTE initiated a
proceeding to implement the market price requirement for Default Service
in June 1999, [^26] noting that A . . . Default Service pricing and
procurement will affect the types and number of bids to supply Default
Service and could have implications for the competitiveness of the
retail market.@[^27] The decision about how to reflect growing market
prices for electricity for Default Service customers will eventually
affect all customers, even low income customers who are exempt from the
Default Service during the transition period. However, after February
2005, Default Service will become the only service that any residential
customer can obtain if they are unable to obtain or retain service in
the competitive market.

In mid-2000, the DTE decoupled Default Service rates from SOS
rates.[^28] The Department ordered utilities to pass through a price
that reflects short term priced service obtained by bids in the
wholesale market. The price must be fixed for six-month intervals or
offered as a month-to-month variable rate for a six-month period.
Residential customers who must obtain Default Service will be
automatically placed on the fixed price rate, but will be offered the
month-to-month variable price as an option. Commercial and industrial
customers will be put on the variable price option and must seek the
fixed rate upon request. Utilities were ordered to obtain bid prices by
customer class, but some utilities stated that they were not able to
implement multiple Default Service prices in their current billing
systems. The Department rejected a suggestion that the Default Service
prices include any administrative costs associated with the procurement
of Default Service or other costs, such as bad debt expense. In a later
Order[^29], the Department clarified that the utility should reconcile
the cost for this service annually and that the over- or under-recovery
would be passed to all customers. The Department=s objective in its
decisions about Default Service was to Asend an efficient price
signal.@[^30]

The new Default Service rates went into effect on January 1, 2001. These
rates are substantially higher than SOS rates, namely 7.032 cents per
kWh at Boston Edison (residential) and more than 8 cents at Fitchburg
Gas and Electric and Western Massachusetts Electric Co. While affected
customers were issued bill notices to explain the forthcoming rates,
bills containing these higher rates were not issued until February 2001.
At the same time that the Department moved to market based rates for
Default Service, it was requested by electric utilities in late 2000 to
make significant increases in Standard Offer Service as well. The basis
for these requests was the rising fuel prices in the wholesale market.
In effect, the utilities sought a fuel clause adjustment to their rates
and alleged that the Restructuring Act did not intend to prevent such
fuel clause adjustments in mandating the 10-15% rate reductions. In a
Letter Order issued on December 4, 2000[^31], the DTE agreed with the
utilities and confirmed that the utilities had been accruing deferred
fuel costs and should not continue to do so. As of August 2000, the
utilities had accrued standard offer service deferrals of \$10 million
for Fitchburg, \$60 million for Massachusetts Electric, and \$144.8
million for NSTAR companies (Boston Edison and two other electric
utilities). These accruals were estimated by the utilities to increase
substantially throughout 2001. The Commission ordered an annual change
in SOS to reflect actual fuel costs incurred by utilities, subject to
reconciliation of actual costs incurred to provide this service.
Utilities were also ordered to inform customers of these price changes
by means of a bill insert.

Customer choice in Massachusetts continues to be only a theoretical
possibility for most customers. Of 2.5 million customers, only 2,463
were on competitive supply as of June 2001 (.1% of all customers). Only
.04% residential customers were taking generation from a competitive
supplier. Competitive suppliers, such as Utility.com and Essential.com,
have either gone out of business or stopped serving residential
customers. Even the much-touted community aggregation program authorized
under the Massachusetts restructuring legislation and initiated by a
consortium of municipalities has been unable to deliver lower price
electricity because the supplier picked by the Cape Light Compact
(Select Energy) backed out under a contract clause that allowed such
action if wholesale power costs increased.[^32] Meanwhile, rates for
both Standard Offer Service (SOS) and Default Service increased
significantly in 2001 and then dropped somewhat in 2002 due primarily to
activities in the wholesale market.

In June 2001 the DTE approved a new round of rate increases for the
generation supply portion of SOS, applicable to the July-December 2001
time period. Residential customers of Boston Edison eligible for SOS pay
7.445 cents per kwh, compared to 6.215 cents during January-June, 2001
or 4.5 cents in 2000. Massachusetts Electric Co. customers (a subsidiary
of National Grid) pay 6.631 cents per kwh, compared to 5.401 in
January-June, 2001 or 3.8 cents in 2000.

Since wholesale power prices have increased significant throughout the
New England ISO since the onset of deregulation in 1998, the price for
Default Service was much higher than for SOS throughout 2001. The
monthly variable rate for the generation or supply portion of the bill
for a Default Service residential customer for the period July-December,
2001 varied among utilities, but was typically 10-11 cents per kwh in
the summer and 7-9 cents in the winter. The fixed rate option was
generally in the 8-9 cents per kwh range. For example, Massachusetts
Electric's fixed residential Default Service rate is 9.213 cents per kwh
for the period May-October, 2001.[^33]

Another way to evaluate or compare the pre-restructuring prices to those
in effect in 2001 would be to compare the total bill price for
residential customers. The graph[^34] shows the average statewide prices
charged for the total bill for SOS and Default Service at each electric
utility in comparison to pre-restructuring prices. The average total
bill for a residential Default Service customer has increased over 30%
since 1998, the onset of retail electric competition in Massachusetts.

![](media/image1.wmf)These prices were substantially higher than
forecast by utilities or regulators or that could be explained by higher
energy prices generally. According to a filing by Western Massachusetts
Electric Co. seeking approval for an energy efficiency plan, actual
electricity prices were 77% higher than that price projections used in
earlier plans to calculate program benefits for 2000 and 2001. These
higher prices for the generation portion of the electricity bill were
almost double the price increases that occurred for heating oil and
natural gas.[^35]

In the face of higher prices and lack of both supplier and customer
participation in retail electric choice, the DTE opened an investigation
into the status of the competitive market, with the avowed intent of
"taking all appropriate steps to bring the benefits of industry
restructuring to electricity consumers."[^36] The focus of the early
steps explored by the DTE was to stimulate supplier interest in Default
Service customers and, based on comments from suppliers gathered at
technical meetings in early 2001, increase supplier access to
information about default service customers. The Commission ordered that
utilities should make available lists of customer name, address, and
rate class to all licensed suppliers who were prepared to serve
customers immediately and then sought comment on whether or how
suppliers should obtain access to further customer-specific information,
such as credit history and load/usage data. In addition, the Commission
sought comments on whether consumers should be able to electronically
enroll with suppliers.

On October 15, 2001, the DTE issued its final order[^37] and, with
respect to the issue of access to customer usage information, stated,
"Access to a customer's historic usage is critical for suppliers to
project what their wholesale costs would be as that customer's retail
supplier" and that the current system to requiring specific customer
authorization by the supplier is "cumbersome and inefficient." \[at 10\]
The Commission stated that it was "convinced that, with proper education
efforts, the vast majority of customers will appreciate the value of
having their historic usage information included on the Customer
Information Lists" \[at 11\] and adopted an "opt-out" system in which
customers can prevent the release of their usage information by
contacting the local utility. This opt out process will require
utilities to provide two consecutive bill messages and bill inserts to
customers to inform them of the release of this information and how to
prevent the release of the information(by telephone or letter),
resulting the first generic release of the Customer List information in
February 2002.

Responding to the general tenor of most commenters, the Commission ruled
that utilities should not provide suppliers with customer's credit or
payment history and that the Customer List should not be filtered by
removing customers with late payment histories. With respect to the
concern that the use of tariffed rate classifications would reveal those
customers on discount rates available to low-income customers, the
Commission required the utilities to use rate classifications that do
not reveal this information to suppliers.

In Phase II, the Commission announced that it would further explore
several important issues designed to further restructuring. First, the
Commission will explore how and whether distribution utilities should
act as "brokers" for its Default Service customers, that is, in
assisting or acting as a middle man to stimulate customer enrollment
with competitive suppliers. Second, the Commission will explore how
municipal aggregators can aggregate Default Service customers within
their municipal boundaries. The pending proposal by the Cape Light
Compact proposal to provide such a service as a pilot project[^38] will
be used to issue generic guidance on this matter. Finally, the
Commission will explore the details concerning Internet-based
enrollment.

It is clear that Massachusetts policymakers are currently set on a
course that will make use of the pricing mechanisms for Default Service
to stimulate the development of a competitive market.

**New York.**[^39] Unlike most other states, New York has implemented
retail electric restructuring by means of administrative decisions by
the Public Service Commission. There is no statutory mandate for retail
electric restructuring. The New York Public Service Commission has
issued orders and approved restructuring settlements that have phased in
retail electric competition for all customers, but the implementation of
restructuring has varied among the different electric utilities. While
the Commission has conducted outreach and education, the level of
shopping activity by residential customers is relatively low.[^40]

In all its restructuring decisions, the Commission required the local
electric utility to provide Default Service, referred to as the Provider
of Last Resort, at least during the transition period, the term and
pricing for which varies by individual utility settlements. In most
decisions, the settlement resulted in either a rate freezes (e.g., New
York State Electric and Gas Co.) or modest rate reductions for
residential customers. Unlike other settlements, however, Consolidated
Edison proposed to provide Default Service by relying on the wholesale
market and passing through this rate on a variable basis every month. At
the time of the restructuring settlement, both Con Ed and the Commission
portrayed the settlement as one that would result in a 10% rate
reduction for customers over the five-year term of the plan.[^41]
However, the plan allowed for Con Ed to pass through its actual
wholesale power fuel costs. This provision has, contrary to the public
statements at the time of the plan adoption, resulted in significant
rate increases for the generation portion of the bill beginning in the
summer of 2000. As of July 2000, Con Ed residential customers were
paying 10 cents per kWh for generation alone, far higher than the 4-5
cents paid by residential customers in upstate New York utilities and
far higher than the 3.3 cents per kWh paid in 1997. The average monthly
bill for residential customers increased from approximately \$52 in
November 1999 to almost \$75 in July 2000 and leveled off at over \$60
by late 2000.[^42] This resulted in a total bill rate of over 19 cents
per kWh, an increase of about 4 cents per kWh since 1999.[^43] The
resulting furor[^44] led to investigations that concluded that New
York=s wholesale market was flawed and Con Edison publicly warned the
Commission that a ACalifornia-type@ situation could result without
prompt action from both the New York PSC and FERC. Both the PSC and Con
Edison initiated petitions to FERC to control prices on the wholesale
market.[^45]

In part due to the experience with market power prices in the summer of
2000, the Commission initiated a major investigation of its competition
policies, including the POLR service.[^46] The Staff was required to
issue a Astrawman@ proposal for POLR service in mid-January 2001.[^47]
Options being considered by working groups included the gradual
elimination of the utility in the provision of commodity services and
the use of a competitive bid to obtain POLR service at market-based
rates. The Staff=s approach is based on the notion that the utility
should ultimately not have any obligation to serve except for regulated
delivery or distribution functions and that customers should be expected
to enter the competitive market by a date certain and then be Agiven@ to
competitive marketers in proportion to the market share obtained by the
marketer. Among the many issues being considered in the Working Groups
is whether the Commission has the legal authority to order or even
approve any utility=s proposal to exit the retail market and become a
Awires@ only utility. The parties have submitted briefs, but no decision
or ruling from the Commission has yet occurred on this significant
issue. However, the comments submitted by the New York Attorney General
and the Staff of the PSC suggest that any move to a model in which the
utilities seek to exit the obligation to serve would not be possible
without a statutory change to the New York Public Service Law.[^48]

Also under consideration in this proceeding is whether New York should
adopt a comprehensive program to assure reasonably priced electricity
for low-income customers. While several utilities have agreed to
small-scale programs to provide bill payment assistance to low income
customers, there is no consensus as yet as to any statewide program
design or funding mechanism for such programs.

The progress and future of electric restructuring in New York continues
to be uncertain, but rising prices, uncertain supply in the New York
City area, and uncertainty about the market monitoring role by FERC
stimulated more public attention to restructuring in late 2000 and early
2001.[^49] Some policymakers have begun to raise significant concerns
and urge the Commission to either slow down or make significant changes
in this process[^50]. While the Public Service Commission continues to
take the leadership role, the New York Assembly[^51] passed an overhaul
of electric restructuring that is unlikely to be favorably received in
the State Senate and is opposed by the Republican leadership, including
the Governor. Meanwhile, rates and bills for consumers served by
Consolidated Edison (Con Edison) and Orange & Rockland customers
continue to reflect volatile wholesale market prices because they are
allowed to pass through wholesale spot market prices to retail
customers. Other New York utility customers are receiving service under
rate caps or mandated rate reductions. As of May 2001, only 189,352
residential customers (5% overall) throughout the state were obtaining
competitive energy service. However, this was a 50% increase since May
2000.[^52]

The New York Commission has refused to review Con Edison's retail rates
and tariff provisions, even in the face of persistent public outcry and
consumer advocates' attempts to force the Commission to review retail
prices charged in the summer of 2000 in light of the statutory
requirement of "just and reasonable" rates.[^53] However, the Commission
has approved a "hedging" mechanism in the market price rate structure
that was implemented beginning in August 2001.[^54] Furthermore, the
ability of New York to survive the summer without significant power
outages and the existence of a price cap[^55] on wholesale prices at
NYISO has tempered the nature of the price spikes that have occurred.
Even so, the rates in effect for New York City residential customers
remained very high in 2001. ConEd provides its customers with estimated
rates for a six-month period every May and November. However, the actual
price charged for the generation supply portion of the bill varies
according to a complicated formula that is designed to reflect the
wholesale market. In the summer of 2001, customers were charged 10.9
cents per kwh in May, 9.37 cents in June, 12.16 cents in July, and .0913
cents in August. Compared to comparable months in 2000, the 2001 prices
were 74% higher for May, 8% lower in June, 9% lower in July, and 26%
higher in August. As a result, prices were higher overall in the summer
of 2001 compared to 2000. [^56]

While all electric utilities have implemented a form of retail
competition for most of their residential customers, the form and degree
of participation by both customers and suppliers in these programs
varies widely. As a result, the Commission initiated numerous working
groups and conferences to grapple with the developments in the retail
energy markets both in and out of New York, the rise in wholesale power
prices on the NYISO, and the lack of uniformity in the models, programs,
and policies in effect for retail competition in the various electric
utilities in 2000. Finally, on July 13, 2001, the Administrative Law
Judges assigned to the Commission's generic competition proceeding
published a Recommended Decision.[^57] Among the more significant
recommendations were proposals to do away with the two-tiered system of
consumer protections and apply the Home Energy Fair Practices Act
policies to all competitive energy providers and require that all energy
providers be directly regulated by the PSC. Also significant was the
recommendation that the Commission adopt an explicit "universal service
goal" for the electric industry and endorse low-income programs and
rates. The Judges recommended as well that the Commission should focus
first on the development of workable wholesale competitive markets prior
to any full-scale implementation of retail competition. With respect to
the Default Service issue, the report rejected the notion of a POLR
service that is more expensive than service from non-POLR providers,
stating that "Charging higher rates for essential energy services to
those who have few, if any additional choices and who may be least able
to afford them was not generally believed to be just and
reasonable."[^58] While favoring competition models that will eventually
remove the utility from the obligation to provide the energy commodity,
the Judges recommended an approach that would not require a specific
POLR, particularly if all energy providers were governed by the same
consumer protection policies and rules and each had an obligation to
serve. However, the Judges did not make clear how all customers would be
migrated to competitive providers, and even the authors recognized that
a POLR would have to exist for short term services, such as when a
provider goes out of business. In the short run, the decision
recommended the continuation of utility-supplied default service until
the wholesale market was viable and could be relied upon to provide
reasonable price signals and stimulate suppliers to make offers to mass
market customers. The Commission has yet to rule on these
recommendations and they remain in limbo as of April 2002.

Upstate New York utilities, such as New York State Electric & Gas
Corporation (NYSEG) and Niagara Mohawk, have proposed multi-year rate
plans in which prices for generation service will be locked in for a 6-8
year period, while providing customers with the option to seek lower
prices in the competitive market. This would substantially lengthen the
transition period for these utilities. NYSEG in particular has been very
vocal about the need to provide stable and fixed prices for residential
customers in particular and in April 2001 published a paper on the New
York State's Electric Energy Crisis that described the "broken train"
that is the New York wholesale market and linked the coming period of
uncertainty in wholesale prices with the need to provide price certainty
to consumers during this transition period.[^59]

**Pennsylvania.** **.** The Pennsylvania restructuring legislation[^60]
provides that the local electric distribution utility must serve as the
default provider for a minimum of three years, after which the
Commission has the authority to establish the method by which the
default provider will be selected. The price of this service must
reflect the rate caps contained in the legislation. Section 2804 of the
Customer Choice Act requires two different rate caps. The first rate cap
is on the charges for regulated distribution service and is operative
for 54 months or until the Competitive Transition Charge (Stranded
Costs) is completed and all customers have choice, whichever is shorter.
The other rate cap applies to the generation portion of the utility=s
rate and is for nine years or until the CTC is completed and all
customers have choice, whichever is shorter. The first rate cap sets a
ceiling for all distribution company rates, both for generation services
sold to customers by the distribution company and for the
distribution/transmission portion of the bill. The second rate cap sets
a ceiling only for the generation portion of a utility=s charges to
customers who purchase generation from the utility, including stranded
cost recovery charges, so that these charges will not exceed Athe
generation component charged to the customers that has been approved by
the commission for such service, as of the effective date of this
chapter,@ i.e., January 1997.

Section 2807(E)(1) of the Act specifies that an electric distribution
company has an obligation to serve, including the obligation to produce
or acquire electric energy for its customers, while such utility
collects stranded costs or until 100% of its customers have choice,
whichever is longer. Section 2807(E)(2) requires the Commission to
establish rules that will govern the provider of last resort service
after the end of the phase-in period. The legislation specifically
authorizes (but does not require) the use of competitive bidding to
obtain POLR service after the end of the transition period. Even so, the
pricing structure of those future rules must still assure compliance
with the rate cap provisions during the period in which stranded costs
are being recovered.

In summary, under the Customer Choice Act, the electric distribution
company must provide generation services to any customer who is not
eligible to choose or who, [for any reason]{.underline}, seeks to obtain
generation services from a distribution company. During the operation of
the rate caps, the price for this generation service cannot exceed the
rates for this service in effect on January 1, 1997. Customers who try
the competitive market and then return to their distribution company
still receive the protections of the rate cap. The only rates that are
not applicable to the rate caps are for new services. Utilities may in
fact seek to obtain this generation service from other sources, but the
total customer bill, in the case of the first rate cap, or the
generation portion of the bill (plus the stranded cost recovery charges)
in the case of the second rate cap, cannot exceed the rates in effect on
January 1, 1997, except for a narrow set of reasons set forth in the
Act. These reasons include a petition by a utility that seeks to
demonstrate that its financial viability is at significant risk unless
the Commission makes a changes in the rates subject to these rate caps.
As a result, Pennsylvania=s legislation provides residential customers
with a Areal@ rate cap that was intended to prevent customers from being
subjected to market prices during the transition period, but would
stimulate customers to leave Default Service if competitive providers
could structure offers that reduced the price of the generation service
or offered additional services to customers.

The statutory rate caps have been extended in numerous settlements of
both restructuring proceedings and other proceedings, such as the merger
between PECO Energy and Unicom in 2000 and the divestiture of power
plants by GPU Energy and Duquesne. Total rates are capped at January 1.
1997 levels until 2005 in many cases and generation rates are capped at
set levels until 2010 in most service territories. Furthermore, the
restructuring proceedings resulted in settlements that in most cases
reduced current rates from 2% to 8%, a result that was not mandated by
the Competition Act. This extended transition period was designed to
make rates stable for customers so that the wholesale market could
develop gradually.

Most important, the Pennsylvania Commission unbundled the utility=s
January 1, 1997 rates in a manner that created a default price for
generation service (referred by the Commission as the Ashopping credit",
a term that does not appear in the legislation) that complied with the
statutory rate caps and was still more than the then-expected retail
market price of electricity. As a result, competitive suppliers were
able to offer retail rates for generation service that were below the
Default Service price in most cases and where the spread between these
two prices was largest, more competitive shopping and supplier activity
has occurred. As of January 1, 2001, 568,492 customers had switched to
alternative suppliers, of which 473,852 were residential customers.
While the percentage of residential customers that have switched varies
by utility, 33% of Duquesne=s residential customers and 16.2% of PECO
Energy=s residential customers have switched. PennFuture[^61] has
estimated that Pennsylvania consumers have saved \$2.84 billion since
January 1, 1997. At the same time, these restructuring case settlements
have resulted in a significant expansion (a fourfold increase in some
cases) of low income bill payment assistance and energy assistance
programs. For example, in PECO Energy=s service territory, 80,000
low-income residential customers are on a discounted rate program funded
through distribution rates. Also, GPU Energy utilities agreed to a
4-fold increase in spending for its Customer Assistance Program, modeled
on a percentage of income payment plan.

The Commission issued Interim Guidelines for Provider of Last Resort
Service (November 19, 1998, Docket No. M-00960890F0017) to govern an
electric utility=s obligations pursuant to the Customer Choice Act.
These guidelines basically set forth the obligations of the electric
distribution utility pursuant to those provisions of the Act already
described above. The most controversial aspect of the guidelines was
whether the Commission should regulate how the utilities should
communicate with its customers about Default Service, some commenters
alleging that some utilities were in effect Amarketing@ to customers to
urge them not to shop or choose an alternative provider. The Commission
stated:

> Since the Commission has a substantial government interest in creating
> and promoting the formation of a vibrant and effective competitive
> market for electric generation, some constraints on PLR (Provider of
> Last Resort) marketing by EDCs are necessary to advance that interest
> and further the intent of the Act. As an incumbent provider, the EDC
> possesses an inherent advantage which could be used to undermine
> competition if unregulated marketing of its PLR role is permitted. In
> particular, the marketing of the PLR function by EDCs needs to be
> restrained to avoid anti-competitive conduct so that the objectives of
> the Act are advanced and fulfilled.

Slip Op. At 14.

This overall policy was then implemented by prohibiting the utilities
from using their customer mailing lists to promote the PLR function
unless the mailing lists were made available to all other competitive
providers for a reasonable fee. The Commission also prohibited utilities
from using consumer education funds (recovered from all ratepayers) to
promote PLR services and emphasized that it would prohibit any marketing
which disparaged competitive providers or implied false facts or made
misleading statements. The Commission also reemphasized that utilities
may impose no conditions on a customer who receives PLR service or who
returns to PLR service. In other words, a utility may not impose any
security deposit or other condition of service for a customer returning
to PLR service if that customer was previously served by the utility.
This policy will prevent the utility from relying on the customer=s
payment experience or unpaid debt owed to competitive suppliers in
providing PLR service.

In response to the actions of some suppliers who cancelled customer
contracts and Adumped@ customers onto POLR service when prices in the
wholesale market increased in the summer of 2000, the Commission issued
an Order[^62] which allowed utilities to file tariffs to require
commercial and industrial customers to remain with POLR service for a
period of 12-months upon a return to this service. However, utilities
are not allowed to impose such terms on residential customers.

Finally, the Commission has approved several individual utility
restructuring plans and settlements that call for the use of a
competitive bid mechanism to select the provider of last resort for some
portion of the electric utility=s residential customers prior to the end
of the transition period mandated by the statute. In the GPU Energy,
PECO Energy, PP&L and Allegheny service territories, the utility was
obligated to offer at least 20% of their non-shopping residential
customers for Default Service by means of a competitive bid. For
example, the PECO Energy restructuring settlement provides that on
January 1, 2001, 20% of all PECO=s residential customers (to be
determined by random selection and specifically including low income and
payment troubled customers) will be Aassigned to a provider of last
resort-default supplier other than PECO that will be selected on the
basis of a Commission-approved energy and capacity market price bidding
process.@[^63] This service is referred to as Competitive Default
Service (CDS).[^64] A key component of all the settlements, however, was
that any bid must comply with the generation rate cap that would
otherwise be applicable to the distribution company. Furthermore, the
settlements allowed the CDS provider to assume the billing and
collection responsibility for the entire customer bill, including the
regulated utility charges, but subject to the relevant consumer
protection and customer care functions in accordance with the same
regulations applicable to electric utilities.

The Commission finalized the guidelines under which the competitive bid
process would occur on April 29, 1999 \[Docket No. R-00973953, and
P-00971265\] and established the qualifications for CDS bidders, the
process by which the CDS provider will be selected, and the terms and
conditions for CDS service. While some commenters sought a bid option in
which the supplier could bid for generation supply alone without the
customer care (billing and collection) function, the Commission rejected
that proposal:

> The winning CDS bidder will perform customer cares functions,
> including: billing, credit, advanced meter reading, collections and
> notices, disputes and disputes resolution, call center activities,
> switching generation suppliers and EDI/EDEWG transactions. PECO EDC
> will perform the following customer cares functions: physical
> termination, restoration of service after a physical termination,
> maintenance and repair of PECO EDC-owned meters, administration of
> universal service programs (CAP, LIURP, CARES and Hardship), call
> center activities related to distribution system outages and
> emergencies, and discontinuance of service.[^65]

In addition, the Commission ruled that revenues associated with
performing billing and collection in conformance with utility rules,
uncollectible expense and universal service costs will be portable with
customers assigned to the CDS provider and will be provided to the CDS
provider to the extent it is providing these services.

In these guidelines the Commission specifically reiterated its
long-standing position that no competitive supplier, including the CDS
provider, could physically disconnect a customer for nonpayment of
competitive charges. A customer may be subject to disconnection for the
failure to pay default or PLR service, but this process must conform in
every respect to that required for electric utilities and only the
electric utility will be allowed access to the customer=s meter to
perform this function. Furthermore, the Commission required the CDS
provider to submit prices for this service based on the Aexact block
rate structure and rate design@ for each customer class. The rates must
be fixed for an annual term and the CDS provider must serve all the
randomly assigned customers.

The Commission refused to adopt a methodology for pricing Default
Service proposed by some competitive providers known as the Astranded
cost prepayment methodology.@ Pursuant to this approach, a bidder
submits a bid which agrees to charge customers the same rates which the
electric utility currently charges, but, at the same time, recognizes
that there is value in providing that service. In recognition of this
value (obtaining a large volume of customers with no marketing or
administrative acquisition costs), the bidder bids a lump sum cash
payment that it would be willing to pay to obtain the bid. This cash
payment was proposed to be applied to the utility=s stranded costs for
all residential customers, not just customers receiving the competitive
Default Service. The Commission rejected this approach because it would
have resulted in higher prices for generation service for those
customers served by the CDS provider and the resulting benefit that was
proposed to be provided to all residential customers was likely to be
small in any case.

However, the bid process, first initiated by GPU Energy in early 2000,
was unsuccessful in attracting bidders for this service at any electric
utility. In the Commission=s approval of PECO Energy=s merger with
Unicom in June 2000, however, it accepted a stipulation[^66] which made
certain changes in the prior restructuring settlement concerning
Competitive Default Service. As a result of these changes, PECO Energy
was able to negotiate for the provision of POLR service with individual
suppliers and eliminate the requirement that the successful bidder
assume the customer care function. Subsequent to these changes to the
"rules" for CDS, the Commission approved[^67] an agreement entered into
by PECO Energy and New Power Company, Inc. that was effective in April
2001. At that time 20% of PECO=s residential customers who had not yet
chosen a competitive supplier were switched to New Power for their
generation supply. PECO Energy continues to bill and collect the total
bill. Customers served by New Power have received a 1-2% discount off
the current PECO shopping credit (price for generation service under the
capped rates).

Pennsylvania's highly touted electric restructuring program began a
gradual slow down, at least as measured by customer shopping statistics,
in 2001. Many competitive suppliers have left the residential market,
some have declared bankruptcy, and others have "dumped" their customers
onto Default Service provided by utilities.[^68] Wholesale market prices
have increased in the PJM area, but there is a vigorous effort led by
the affected states to establish PJM wholesale market rules that
discourage California-type price spikes and provide demand side options
when prices do spike. However, while shopping by residential customers
may be slowing down or even stopped entirely in some service
territories, residential customers remain protected from any price
spikes in the wholesale market and the universal service programs (both
energy efficiency and bill payment assistance) are expanding due to
restructuring proceedings and settlements.

Since July 2000, the number of suppliers has dropped significantly and
the number of residential customers served by alternative energy
providers has fallen from 444,154 to 322,000 as of October 1, 2001 (this
figure excludes Competitive Discount Service customers, a service that
is discussed in the next paragraph). In most utility distribution
service territories the percentage of residential customers served by
alternative suppliers is less than 1%, with the exception of Duquesne
Light (31%) and PECO Energy (10.9%, a percentage that excludes
Competitive Discount Service customers).[^69] Also, the number of
suppliers remains very small, only one-two in most cases, with one of
those typically a "green" provider at higher prices than the utility's
default service. In a significant blow to the appearance of competition
in a state that touted itself as a national leader in electricity
competition, even the CDS program has failed. New Power announced in the
spring of 2002 that it would end its provision of this service and
return all its customers to PECO Energy prior to its contractual
obligation. The failure of competitive providers, particularly New
Power, has led Pennsylvania's Consumer Advocate to describe any Provider
of Last Resort other than the local utility as the "Provider of Next to
Last Resort."

While the statutory rate caps (most of which were extended in various
restructuring proceedings and settlements in 1998) remain in place at
most utilities, GPU Energy initiated a proceeding to increase rates and
break the rate caps in place for its two Pennsylvania electric
distribution companies (Metropolitan Edison and Pennsylvania Electric)
at the same time that it applied for approval of a merger with
FirstEnergy, a Ohio utility. GPU Energy sought to raise prices because
it had relied almost entirely on the wholesale market for the power
supply necessary to provide default service after it had divested most
of its power plant facilities and the company claimed that those
wholesale prices had risen unexpectedly compared to the predictions
associated with deregulation in 1997 and 1998. The Commission linked
this request to the company's merger proceeding. On May 24, 2001, the
Commission issued an order that approved the merger, but postponed a
decision on GPU's request to raise rates. With respect to the proposed
rate increase, the Commission convened a collaborative meeting to seek a
negotiated settlement. A settlement was reached among most parties and
the Commission approved it on June 14^th^, stating, "The settlement
allows GPU to defer for ratemaking and accounting purposes the
difference between what it must charge customers for generation under
the rate caps and ita actual cost to supply electricity. Customer rates
will not increase, but the electric choice shopping credit will rise,
possibly allowing more customers the opportunity to ahop for a
competitive supplier." [^70] As a result, the customer's total bill will
not increase, but GPU can defer any excess wholesale power losses
through 2005 and carry them on the company's books until 2010. At that
point, wholesale power losses will be used to offset and reduce the
deferred losses, with any losses remaining at the end of 2010 being
written off. A number of parties appealed this decision and the case is
currently pending before the Pennsylvania Supreme Court.

Finally, at least one PUC Commissioner has publicly begun to question
the notion that rate caps are beneficial to consumers. According, to
Commissioner Terrance J. Fitzpatrick,[^71] there are two policy changes
that would enhance competition in retail electricity markets, while
still protecting consumers from unreasonable price increases. He
proposes that the PUC be given discretion to set a utility's generation
charges at a level that is linked to some degree to actual wholesale
costs. Second, utility generation charges should be gradually modified
to reflect variations in the value of electricity caused by supply and
demand. He argues that utility generation charges should reflect the
reality that electricity is more valuable during period of high usage.

**Texas.** The Texas electric restructuring statute was enacted in
1999[^72] and calls for the implementation of retail electric
competition for all customers beginning January 1, 2002. The Texas
industry model is different than that adopted in most states. Under the
Texas approach, customers will obtain electricity service from a "retail
electric provider" or REP. A REP will have the sole retail relationship
with its customers and will obtain the necessary transmission and
distribution services on a wholesale basis from the former public
utilities. The REP is responsible for all of the necessary contacts with
customers, as well as billing and collection for the total electricity
service. As of January 1, 2002, all customers were switched to the
"affiliate" REP, the retail REP formed by the former local electric
utility to provide electric services to customers under the Price to
Beat.

The affiliate REP must provide service to all customers who are
transferred to this service under the "Price to Beat" rate, which is at
least 6% less than the rates in effect in 1999[^73]. In effect, the
affiliate REP will provide Default Service under a rate reduction scheme
that resembles that in most states. However, customers who are
transferred to the affiliate REP will have left their "utility" and
entered the competitive market, albeit at a rate that is regulated for a
transition period. The Price to Beat will remain in effect until January
1, 2007 (five years) or until at least 40% of the residential load
served by the former electric utility is being served by a non-affiliate
REP. Unlike the rate caps in effect in Pennsylvania and several other
states, the Price to Beat rate is subject to adjustment based on the
cost of fuel at least twice per year.

Another aspect of the Texas restructuring model that is unique is the
role played by the Electric Reliability Council of Texas or ERCOT. The
wholesale power market in most of Texas is under the control of the
Texas PUC and not subject to the jurisdiction of the FERC. As a result
of this anomaly, Texas is truly a "world unto itself" for electric
regulation. ERCOT plays a crucial role in retail competition, as well as
its paramount role in assuring reliability of service and proper pricing
of transmission service in the wholesale market. ERCOT sought to provide
the retail customer database for all REPs and supplant the role
typically played by the local distribution utility in most states to
implement customer access to competitive providers. Under the Texas
approach, a customer selects a REP who then submits a switch order to
ERCOT. ERCOT then implements that switch by informing the customer of
the impending switch via postcard that allows the customer 10 days to
cancel without penalty. ERCOT also electronically informs the new REP of
the customer's premise, usage and meter information which ERCOT obtains
from the distribution company. Finally, ERCOT informs the old REP of the
customer's "drop" of service. ERCOT has constructed a database that
assigns every retail electric customer a unique identifier so that
customers can be properly matched with their REP of choice (or their
local affiliate REP if they do not choose).

One of the most closely watched aspects of the Texas version of retail
electric choice was the operation of the ERCOT switch procedures which
were tested in a pilot program that began in July 2001. Under this pilot
program, a certain percentage of customers for each utility were allowed
to select a competitive REP. While there was a reasonable level of
interest in this program by residential customers, particularly in those
utility areas that received marketing attention from several REPs who
offered service below current rates, there was significant delay and
controversy in the operation of the ERCOT database and switching
program. Most of the switches that occurred in the early months were
manually handled and the automated switch process was not operating a
full speed until late in 2001. Most customers who selected a REP were
not switched in time to receive more than one bill during the pilot
period and prior to need to decide whether to move to full-scale
competition on January 1, 2002.[^74] While there was some debate as to
whether the PUC should have recommended a delay in the January 1
implementation, the PUC in fact did recommend that the full scale
competition program and the switch of all customers to the affiliate REP
should occur on January 1, 2002.[^75]

The number of competitive providers that participated in the pilot
program varied by utility service territory, but was modest at best.
Furthermore, one of the larger participants, Shell, dropped out of the
retail market and its customers had to either go back to the utility or
select another REP. As of January 2002, 8 REPs were marketing in the TXU
Energy (Dallas area) and Reliant Energy (Houston area) service
territories, but only 2-3 REPs were marketing in Texas-New Mexico Power,
West Texas Utilities, and Central Power and Light areas. According to
the PUC's report to the Texas Legislature's Restructuring Oversight
Committee on February 5, 2002,[^76] the range of savings (compared to
the Price to Beat) varied among the REPs and was dependent on a
customer's usage profile. For example, several REPs in the Reliant
service territory were offering higher prices (Green Mountain Energy for
100% renewable power), but most offered savings in the 2-10% range for
an average bill. In almost all cases, customers who used significantly
below the average usage level of 1,000 kWh (i.e., at 500 kWh) would
experience rate [increases]{.underline} from all REPs because of the
effect of the REP rate structure.[^77] The PUC has publicly reported
that approximately 150,000 customers have switched to competitive
providers as of mid-February 2002, but the PUC does not yet provide
switching information on its website.

One of the most aggressive marketers is New Power Energy, which is
offering two plans: "Basic Service Plan" (which shows a savings of 12%
for users over 1,000 kWh per month in the Reliant territory) and "Texas
Super Saver" (which shows a slightly lower level of savings at all usage
categories, but locks in rates for a longer fixed period). This company,
which was owned in part by Enron, announced that Centrica, a U.K.-based
energy company that also markets energy under the names of Energy
America and Direct Energy, agreed to buy New Power, but this proposed
acquisition was cancelled by Centrica in April 2002 because of its
concerns about risks associated with liabilities incurred by Enron.
Energy America is best known for its controversial practices in
obtaining customers by door-to-door marketing[^78] and New Power has
also recently initiated a large-scale door-to-door marketing campaign in
Texas.

Most observers expect that more intense marketing will occur during the
spring and summer period in Texas when electric bills are normally
higher due to the air conditioning load and hotter temperatures.

Customers who do not qualify for the Price to Beat rate or who are
terminated by the REP for the failure to pay or maintain service
conditions will not be physically disconnected. Rather, such customers
will be transferred to the Provider of Last Resort service. This service
must be provided by an entity selected by the Commission according to a
bidding procedure that is designed to replicate the competitive market.
The Commission issued final rules that govern the bidding process for
this service and sought bids according to a Request for Proposals in
mid-2001.

Pursuant to the Commission's rule, the POLR service will provide a
basic, standard retail service package to any customer no longer served
by the customer's REP or whose REP defaults in its obligations to the
distribution utility or with respect to other license conditions. The
POLR service is viewed as a safety net service, but will also be
available to any requesting customer. POLR rates will distinguish
between three customer classes: residential, small commercial, and large
commercial customers above 1 MW. The POLR price will be a fixed,
non-discountable, seasonally differentiated, firm rate that must be
fully hedged or fixed for the time period of the bid, established as a
minimum of one year. The POLR service will not include any competitive
service offerings, innovative rate structures, or options other than
basic, standard rates and service options. The POLR provider has an
obligation to serve, but may deny service based on the same criteria
applicable to utilities under the Commission=s pre-restructuring
consumer protection rules. There are no minimum service terms or fees
associated with this service, except that a customer that elects a
levelized or budget payment plan (which the POLR provider must offer)
may be required to agree to a six-month term of service. Only the POLR
provider may disconnect service for nonpayment. While customers who are
"dropped" by a REP will automatically be transferred to the POLR, such
customers can seek to return to the Price to Beat service at any time,
subject to the payment of any deposit or other credit requirements
imposed by the affiliate REP. Such customers can also seek service from
any REP in the competitive market. Customers will not be required to pay
the "old" REP's unpaid debt to leave a REP and choose another or return
to Price to Beat rates under the affiliate REP.

The PUC intended to award the POLR service based on competitive bids.
However, the competitive bidding process failed to obtain sufficient
bids that were deemed acceptable by the Commission. Finally, on July 27,
2001, the Commission appointed Assurance Energy, an affiliate of TXU
Energy, as POLR for residential and small business customers in portions
of the service territories of Reliant HL&P, Central Power & Light, and
Entergy Gulf States, and negotiated contracts with Entergy Solutions to
serve customers in northeast Texas (SWEPCO) and with First Choice Power
to serve customers in the western portion of TXU's turf. Rates were
established for the first six months of 2002, but the contrast between
the POLR rates with the current utility rates and the forthcoming Price
to Beat (6% less than current rates) to be charged by the affiliated
REPs next year were stark. Assurance Energy's contract reflected POLR
rates for residential customers at 14.9-15.9 cents per kwh (inclusive of
generation and distribution charges) in the summer and 11.9-12.9 cents
per kwh in the non-summer months, plus a \$10 monthly customer service
charge. As a result, the POLR will charge an average of \$164 and \$134,
respectively for a customer using 1,000 kwh for POLR service. However, a
residential customer of Reliant HL&P paid only \$110 for 1,000 kwh in
July 2001, resulting in a 50% rate increase for a customer who must use
POLR service because the REP has cancelled the contract or stopped
providing service for any reason. POLR customers served by other
appointed POLR providers in other service territories are likely to pay
even higher rates compared to Price to Beat customers.

The Commission later signed contracts with StarEn Power (an affiliate of
Reliant) to provide POLR services for the TXU customers in the
Dallas-Fort Worth area and First Choice Power (an affiliate of TNMP) to
provide POLR services to the TXU west service area other than DFW. These
contracts also approve extremely high electric rates compared to current
or projected Price to Beat Rates.

In addition to the higher rates for electricity, the contracts contain a
number of additional fees and charges that will result in higher bills
for affected customers, such as an account initiation fee (amounting to
a switch fee for being changed to POLR service), and requirements for
deposits or prepayment for service that must be paid within 10 days of
initiating service for those customers with poor or no credit history, a
barrier to service that will likely apply to customers who reach the
POLR due to the failure to meet the bill payment requirements of the
REP. The POLR can seek to disconnect service for nonpayment of these
deposit or prepayment requirements.

The initial POLR rates negotiated and approved by the PUC were highly
criticized by consumer organizations and several Legislators who were
members of the Restructuring Oversight Committee. In addition, the
Office of Public Advocate filed appeals of the Commission's POLR orders,
alleging procedural and due process defects in the manner in which the
contracts were negotiated and approved. Furthermore, the drop in price
for natural gas (a key determinant of electric rates in Texas due to the
prevalence of natural gas as the generating fuel) also suggested that
the POLR rates were too high. As a result, the Commission re-negotiated
the POLR contracts and the final rates, while still 20-30% higher than
the Price to Beat in all cases, are lower than the original POLR rates:

**Comparing 2001, Price to Beat, and POLR Residential Rates**[^79]**:**

Corpus Christi Houston Dallas

12/2001 Rate 9.57 10.40 9.67

PTB Rate (1/2002) 8.80 8.62 8.25

POLR Rate 10.72 10.86 8.40-10.24

POLR as % of

2001 Rate 112% 104% 86-106%

POLR as % of

PTB Rate 122% 126% 102-124%

These rates do not include the separate fees charged by most POLRs for
new account initiation, deposits, or separate fees for certain
collection activities, such as issuing a disconnection notice or
conducting a premise visit.

Consumer organizations are concerned with more than the POLR price,
however. They fear that REPs, including the affiliated REP, will cancel
customer contracts at a much higher frequency than utilities used the
disconnection tool in the past in order to rid themselves of credit
risky and payment troubled customers, thereby making it easier for the
affiliated REP to provide the Price to Beat rates and still make a
profit. As is typical of utilities in most states, Texas utilities have
issued a vast number of residential disconnection notices each month,
but only disconnect a very low percentage of those customers who are
"eligible" for disconnection under the consumer protection rules.
Furthermore, Texas utilities actually disconnected residential customers
at significantly different rates, according to statistics gathered by
the Texas Legal Services Center. Consumer advocates argue that the
affiliated REP or any REP will have no incentive to retain customers and
work with them to avoid termination of service when there is no risk to
the REP by canceling the customer's contract and transferring the
payment problem and the increased collection costs associated with such
customers to the POLR. Will payment troubled customers be able to obtain
lower priced service from alternative REPs or will the electric version
of the "phone sharks" appear that promise payment troubled customers a
lower rate than POLR, but a much higher rate than the Price to Beat
service? While customers can seek to transfer to the Price to Beat
service from the affiliate REP, will they understand this right and be
able to do so with the required credit requirements that the new REP can
impose? Will they understand the penalty imposed by moving to POLR
service (in the form of much higher prices) until the bill becomes
unaffordable and disconnection inevitable? These are the questions that
are troubling both the consumer representatives and the Commission as
they move into retail competition in early 2002.

The Commission promised the Legislature's Oversight Committee that it
would review the POLR rule in early 2002. A workshop was held to review
potential alternatives to the structure of the POLR service and the POLR
selection process on February 26, 2002, after which the Staff published
a proposal for public comment[^80] that would make a significant change
in POLR service. Under the Staff's draft, customers who are terminated
by REPs would not be automatically transferred to the POLR provider, but
rather transferred to the Affiliate REP and served at Price to Beat
prices during the transition period. POLR service under the higher
priced contracts would be restricted to those residential customers
whose REP defaulted or who failed to choose a REP at the initiation of
service at a new location. The Affiliate REP would have the authority to
seek physical disconnection of service under the same rules as applied
to the incumbent utilities under this approach. This is a significant
policy shift and would protect the vast majority of residential
customers who were likely to be transferred to the POLR from having to
maintain electricity service at high prices compared to other customers
served by Price to Beat rates.

As part of the electric restructuring legislation, low-income electric
customers (defined as those with household income at or below 125% of
federal poverty guidelines) are eligible for a rate discount of 10% (or
more, depending on available funding) that must be provided by all
REPs.[^81] Texas is also attempting to lead the way by using automatic
enrollment procedures to reach eligible customers. All recipients of
Food Stamps, TANF, and Medicaid or Low Income Medicare will be
automatically enrolled in the low-income electric discount under the
LITE-UP TEXAS program. This automatic enrollment is being accomplished
by means of an electronic data transfer from the Texas Department of
Human Services to ERCOT, the keeper of the customer database. However,
there have been reports that this database transfer is encountering
problems in enrolling eligible customers promptly[^82] and low-income
advocates have called for expedited enrollment procedures and urged all
REPs to solicit eligibility and enrollment directly from customers.
Low-income customers who are not already enrolled in the underlying
financial assistance programs may self-certify their income eligibility
by filling out an income calculation worksheet.

. Under consumer protection rules adopted by the PUC, a REP is subject
to a broad array of consumer protections that are similar to those that
applied to the former electric utilities. However, the PUC ruled that a
REP, including an affiliated REP offering Price to Beat service, cannot
disconnect customers for nonpayment, but can only terminate a customer's
contractual relationship. ERCOT will automatically transfer customers
without a REP to the POLR, an entity that will have an obligation to
serve customers who cannot obtain or do not have service from a REP for
any reason. Unlike REPs, the POLR can disconnect a customer for
nonpayment, using the traditional utility procedures and options for
payment arrangement and reconnection.

**Ohio:** Ohio also adopted retail electric restructuring in 1999, with
an implementation date of January 1, 2001.[^83] This legislation retains
the utility as the Default Service provider and establishes rate caps
for the Amarket development period@ through 2005. Except for certain
energy efficiency and universal service riders and the effect of
taxation changes, the unbundled rates must not exceed the total bundled
rates in effect in 1999. Where the Ohio PUC had already approved rate
decreases or such decreases were scheduled to go into effect, the
restructuring statute preserved and mandated those rate reductions as
well. In addition, the generation portion of the bill for residential
customers only must reflect a 5% reduction (that will appear on the
customer=s bill in the form of a credit) during the transition period.
This rate reduction may be altered or removed by the Commission no
earlier than 2003 if the Commission finds that it has unduly discouraged
market entry by competitors.[^84] However, the extent to which the
generation rate reduction is in effect has been the subject of
negotiations and settlement provisions in the various utility transition
plans. The utilities were not required to divest their generation
resources. These rate caps are firm and do not include an exception for
increased fuel costs. During this period the utility remains obligated
to provide Default Service. This aspect of Ohio's restructuring program
is similar to the default service and rate cap policies in effect in
Pennsylvania.

Ohio has also legislatively endorsed the PUC=s long standing universal
service programs for low-income customers. The Percentage of Income
Payment Plan (PIPP), in which low income customers are required to pay
no more than 15% of their annual household income for electricity and
natural gas service, will continue and be integrated with the federal
LIHEAP or fuel assistance program administered by the Ohio Department of
Development. Riders that are included in regulated utility rates and
paid by all customer classes will fund this program, as well as
increased energy efficiency programs.

An interesting and unique feature of the Ohio legislation is the
emphasis on customer aggregation. Municipalities may adopt an ordinance
that aggregates all residents within its boundaries. This aggregation
program, if adopted by an ordinance, may use the Aopt out@ method. Under
this method, all residents are automatically included in the aggregated
group unless they choose not to participate. Residential customers may
opt out of the aggregated group every two years without paying a
switching fee.[^85] A municipality may also use the Aopt in@ method in
which the town negotiates a price with a supplier and residents must
then sign up with the local government, permitting it to purchase
electricity on their behalf. Those who do not provide affirmative
permission will remain with the local utility in Default Service or may
select another competitive supplier. Ordinances which specify that Aopt
out@ method were adopted by hundreds of Ohio communities in the fall of
2000. Subsequently, a consortium of northern Ohio municipalities formed
to serve nearly 400,000 customers in the area surrounding Cleveland
negotiated a contract with Green Mountain Energy Co. for a six-year
supply contract to serve customers in FirstEnergy=s service territory.
Service was initiated in September 2001. Such contracts are possible in
part due to the restructuring settlement reached for the FirstEnergy
proceeding that was approved by the Ohio PUC in which 20% of the
utility=s generation was made available to competitors in the early
years of competition.[^86]

The Default Service obligation under the rate cap provisions continues
through the market development period, i.e., through 2005. Beginning in
2006, the restructuring legislation requires the distribution utilities
to offer a market-based price for this service obtained through
competitive bidding. The Commission must adopt rules setting forth this
competitive bid process by January 1, 2004[^87].

In the Commission=s restructuring rules, customers may be subject to a
minimum stay requirement for Default Service. Customers who switch
during the summer months will be subject to a 12-month minimum stay
provisions, but customers who switch back into Default Service during
any other month may do so without restriction. Additionally, residential
customers are not subject to any minimum stay requirements during the
first year of competition, i.e., calendar year 2001. The Commission has
also approved a maximum \$5 switching fee.

**Maine**: The Maine restructuring legislation[^88] has taken the
boldest step in the elimination of the current utilities from the retail
sale of generation service. Utilities were required to divest[^89] their
key generation sources and the Standard Offer Service must be priced
according to a competitive bid supervised by the Commission. While
utilities are responsible for delivering the Standard Offer to its
customers, the generation portion of this service must be obtained in a
bid process regulated by the Maine PUC. The PUC has promulgated
regulations governing this procurement of Standard Offer Service and
awarded the first competitive bid for this service effective March 1,
2000, when retail competition began for all customers.

Unlike Massachusetts, Maine has only one Standard Offer and customers
are not restricted as to their movement into or out of this service.
Furthermore, there are no statutory rate caps or rate reductions
applicable in Maine. Therefore, the price for generation service
obtained as Standard Offer service will operate as the Aprice to
compare@ for customers contemplating a move to the competitive market.

Pursuant to the Commission=s rules,[^90] the residential rate for this
service must be in a fixed cent per kWh that does not vary by level of
usage or time of year or day. Bidders must submit rates for a minimum
one-year period. Providers must agree to accept any or all customers in
one of three rate classes: residential and small commercial; large
commercial; industrial customers. Therefore, all residential customers
will remain as a block. If more than one provider is selected, rates
will be averaged among the providers for the particular class in
question and rates may not vary based on customer location within a
specific service territory. The distribution utility will issue a single
bill to Standard Offer customers that will show all unbundled charges
and prominently display the name of the Standard Offer provider. As part
of the responsibility for billing and collecting the total bill, the
distribution utility can charge the provider the incremental costs of
administering standard offer service, including bill issuance, bill
calculation and collection. Each standard offer provider will be
allocated a share of the uncollectible accounts in the standard offer
class or classes the provider serves in a manner that reflects the
provider=s share of sales in the applicable standard offer class. The
reasonable costs incurred by the distribution utility in collecting this
service, including uncollectible accounts, can be recovered as part of
the revenue requirement of the utility. Residential customers cannot be
charged a fee to obtain this service unless the Commission determines in
a later proceeding that a fee applied to those customers who are
frequently switching from competitive to Standard Offer service or vice
versa is warranted.

As required by the Maine legislation, a large investor-owned
distribution utility may not provide standard offer service except
through an affiliate, and the affiliate may submit a bid for only a
maximum of 20% of a standard offer class within its own service
territory.

The Maine PUC issued three RFPs on August 2, 1999 for the standard offer
service for the three investor-owned utilities, but then rejected the
proposals (of which there were only a few) for the two largest utilities
on October 25, 1999. A new solicitation ensued with somewhat different
bid criteria which allowed bidders to link their Standard Offer bid
price offers to the concurrent utility RFP process for the sale of each
utility=s generation entitlements to Qualifying Facilities contracts,
most of which are classified as renewable energy sources. On December 3,
1999, the Commission selected a successful bidder for the largest
utility for the residential and small commercial class at a rate of
\$0.04089/kWh.[^91] This has been widely viewed as a relatively low
price that is likely to lessen marketer interest in competing for
residential customers. The successful bidder offered this fixed rate for
two years, which the Commission accepted. The Commission did not receive
an acceptable bid for other classes and the utility was ordered to
obtain the necessary generation service on the wholesale market and
provide this service at an administratively determined price.

Other Maine utilities (Bangor Hydro-Electric Co. and Maine Public
Service Co.) did not receive bids that were deemed acceptable by the
Commission so that those utilities were ordered to go into the wholesale
market and obtain power for its Standard Offer customers. Bangor Hydro
decided to obtain the necessary electricity by using the spot market and
short-term contracts. As a result, when the wholesale power rates
increased in the summer of 2000 throughout New England, it sought and
obtained permissions from the PUC to increase rates significantly for
residential (and other) customers. Effective October 1, 2000,
residential rates increased to 6.016 cents per kWh, an increase of 32.5%
for the generation power of the bill and a 10-12% increase in the total
bill. As a result, customers of Bangor Hydro (approximately 30,000
customers) saw their Standard Offer rates increase similarly to those
approved in Massachusetts. Small commercial customers for all three
electric utilities have also seen significant rate increases as a result
of their market-based rates. However, residential customers of Maine=s
largest electric utility (Central Maine Power) were provided with stable
rates that remained below wholesale market rates until March 2002.

The Commission then undertook a new round of bid solicitations for all
three investor-owned utility customers in late 2001 and announced new
rates, effective March 1, 2002.[^92] The Commission accepted a bid offer
from Constellation Power Source Maine that will result in a very small
rate increase for generation service for Central Maine Power Company's
residential customers (from 4.09 cents per kWh to 4.950 cents per kWh),
a rate that was widely viewed as acceptable in light of the high
wholesale power prices that had been in effect earlier in the year. Even
more importantly, the Commission accepted a three-year contract, thus
locking in these rates. The result of this latest bid solicitation also
resulted in lower prices for Bangor Hydro-Electric Company's residential
customers (from 7.3 cents per kWh to 5 cents per kWh) from the same
provider. As a result of this bidding process and the resulting retail
rates, the Maine Commission has promoted its approach to the provision
of Default Service. Certainly, the prices obtained through this process
are lower than those paid by Default Service customers in Massachusetts.
However, there is one important aspect of these prices that may not be
necessarily replicated elsewhere. The successful bidder was able to
obtain rights to the purchase of utility entitlements at specified
prices as a condition of the bid award. As a result, the successful
bidder was able to access utility Qualified Facility contracts at prices
that no doubt contributed to the provider's ability to offer the
three-year fixed prices. Finally, whether the Commission's decision to
enter into three-year contracts at fixed prices will be viewed as
positive will depend on the future wholesale market prices available in
the New England power market when new generation is due to come on line
in 2002 and 2003.

**Connecticut:** Connecticut=s restructuring legislation[^93] mandates
retail competition for all customers by July 2000. The Legislation
promised that total rates must be reduced by10% compared to rates in
effect on December 31, 1996 and that this rate reduction must remain in
effect through the transition period (2000-2003). Similar to Maine,
utilities must divest their non-nuclear generation resources in order to
collect stranded costs. There is no deadline for the recovery of these
costs and, in fact, the DPUC will set the recovery period for this costs
to accommodate the legislatively mandated rate reduction for the early
years of competition. Rates were reduced at the two largest utilities by
4-5% in anticipation of electric retail competition in 1999. The
additional reductions to meet the 10% reduction in the total bill
occurred on January 1, 2000. Utilities are obligated to provide Standard
Offer Service for the transition period (2000-2003) to any customer who
does not shop which must be obtained, in part, by a competitive bid
process. Beyond that date, there is no legislative mandate for regulated
rates for generation service. Effective January 1, 2000, all customer
bills show unbundled rates and a separately stated Generation Service
Charge. The Department Public Utility Control (DPUC) recently completed
proceedings in which the Standard Offer rate was established for its two
largest investor-owned electric utilities.[^94]

In its decisions, the DPUC determined that the Generation Service Charge
must reflect the retail price to provide energy, that is, the wholesale
price plus marketing, personnel, overhead, taxes and profit. The latter
group of costs was estimated as \$0.005 per kWh to \$0.01 per kWh. For
United Illuminating residential customers the GSC will be five cents per
kWh (4.3 cents per kWh for residential heating customers). This price
was approved based on a settlement between the utility and Enron in
which Enron offered to provide the Standard Offer service for a
four-year period. The GSC rate for Connecticut Light and Power customers
was set after CL&P conducted an auction for 50% of its Standard Offer
needs (50% will be provided by the utility=s affiliate, Energy Select).
In September 1999, the independent bidding agent received eight final
bids to provide portions of the approximately 2,000 MW put out to bid.
Based on the least cost standard offer bid provided and other contract
terms, the CPUC accepted bids from NRG Power Marketing, Inc. and Duke
Energy Trading and Marketing Northeast L.L.C. Residential customers will
pay a GSC rate of 5.5 cents per kWh. These bids are for a fixed price
through 2003 and will not vary by price spikes in the wholesale market.
The bids allowed the DPUC to implement the 10% total bill rate
reduction.

Unlike the bidding process in Pennsylvania, however, these bids were
conducted by the utility in the wholesale market. The winning bidders in
Connecticut will not Aget@ the customers nor do the customer bills name
the power supplier. Rather the price obtained by the utility for this
transition obligation to provide SOS will be passed through on the
utility=s unbundled bill and all customers remain with the utility
unless the customer selects a competitive provider.

SOS customers in Connecticut can move in and out of this service, but
the utility can implement a 12-month stay requirement once a customer=s
returns to SOS after entering the competitive market the first time.
However, utilities may not impose a switching fee or a higher SOS rate
to returning customers.

ENDNOTES:

[^1]: Georgia has implemented a natural gas competition program for
    Atlanta Gas Light that requires customers to select a competitive
    marketer by a date certain. Those who were remaining were assigned
    to a competitive marketer, but this program has not been replicated
    for electric competition in any state. The experience of the Atlanta
    Gas Light program has been controversial. See, e.g., Greene, Kelly
    and Brooks, Rick, "Georgia's Gas Deregulation is Messy, but Offers a
    Lesson to Other States," [Wall Street Journal]{.underline}, January
    15, 2001. In late 2001 the Governor appointed a Blue Ribbon Task
    Force to examine the current program and propose reforms. The
    Georgia Legislature recently adopted significant reforms, including
    more specific consumer protection and customer service obligations
    for competitive providers and the creation of a subsidized Default
    Service for customers who cannot obtain service or who are
    disconnected for nonpayment. HB 1568, see
    <http://www.legis.state.ga.us/Legis/2001_02/sum/hb1568.htm> .

[^2]: Of course, many advocates maintain that residential and small
    commercial customers are unlikely to ever see substantial benefits
    as a result of the move to retail electric competition. However,
    that issue is not addressed in this paper.

[^3]: Pennsylvania Electric Shopping Statistics, January 2001, published
    quarterly by the Office of Consumer Advocate and available at
    [http://www.oca.state.pa.us](http://www.oca.state.pa.us/)

[^4]: Regulators define Stranded Costs as those costs that the utility
    would not recover in a competitive market for investments in
    generation that were approved under traditional cost of service
    regulation.

[^5]: As of the writing of this paper, the Texas PUC has opened a
    proceeding to consider a change in the method of providing POLR
    service to residential customers whose service is terminated by a
    competitive electric provider for nonpayment. The discussion of the
    Texas model in this report summarizes the new approach that is the
    subject of public comment.

[^6]: As quoted in Caffrey, Andrew, "Undoing Deregulation," [Wall Street
    Journal]{.underline}, September 15, 200,
    [http://interactive.wsj.com/archive/retrieve.cgi?id=SB1000471406896519973.djm]{.underline}

[^7]: NEMA, [National Guidelines for Restructuring the Electric
    Generation, Transmission and Distribution Industries]{.underline},
    Washington, D.C., January 1999. Also, Press Release, "National
    Energy Marketers Association Cites Political as well as Economic
    Factors for Price Volatility," August 8, 2000.

[^8]: NEMA letter to the New York PSC, Case 96-E-0891, March 16, 2001,
    available on NEMA's website: [http://www.energy
    marketers.com](http://www.energy/)

[^9]: FERC, Staff Report to the FERC on the Causes of Wholesale Electric
    Pricing Abnormalities During June 1998, Washington, D.C., September
    22, 1998; FERC, NSTar Services Company, Order on Complaint and
    Conditionally Accepting Market Rule Revisions, FERC, Docket No.
    EL00-83-000 et al., Washington, D.C. July 26, 2000.

[^10]: Both the National Electric Reliability Council (for wholesale
    electricity markets) and the Gas Industry Standards Board (for
    retail electric and natural gas markets) have called for the
    development of uniform standards and business practices for
    competitive markets. GISB has now been transformed into the North
    American Energy Standards Board (NAESB). See
    [http://www.naesb.org](http://www.naesb.org/). These developments,
    coupled with the growing role of FERC in the wholesale market and
    the impact of the wholesale market on retail rates, has shifted the
    debate about prices from the various state regulatory commissions
    and their statutory consumer advocates to federal fora.

[^11]: . AB 1890, eff. September, 1996.

[^12]: . This listing and explanation is taken from the residential
    Southern California Edison bill which appears on its website:
    [http://www.sce.com]{.underline}

[^13]: . ACPUC Approves Settlement of SDG&E Changes Once Capital
    Investment is Paid Off,@ CPUC Press Release, May 27, 1999. See also
    the SDG&E tariffs and residential bill explanation at its website:
    http://www.sdge.com

[^14]: . California PUC, [Final Opinion Regarding Policies Related to
    Post-Transition Ratemaking]{.underline}, Decision 00-06-034, June 8,
    2000.

[^15]: . California PUC, [Interim Opinion Regarding Emergency Requests
    for Rate Increases]{.underline}, Decision 01-01-018, January 4,
    2001.

[^16]: . ABx1, enacted February 1, 2001.

[^17]: . [San Francisco Chronicle]{.underline}, A70% to Pay Bigger
    Bills, PG&E Says Firm=s Estimate Higher than PUC Chief=s,@ March 29,
    2001, URL:
    http://www.sfgate.com/cgi-bin/article.cgi?file=/chronicle/archive/2001/03/29/MN90356.DTL

[^18]: . Senate Bill 390 (1997), AElectric Utility Industry
    Restructuring and Customer Choice Act@ (Title 69, Chapter 8, MCA).

[^19]: . [Dow Jones Newswires]{.underline}, AMontana=s Industries
    Pinched by High-Flying Power Prices,@ January 22, 2001,
    http://interactive.wsj.com/arichive/retrieve.cgi?id=BT-CO-20010122-0011943.djml.

[^20]: CPUC Release, "CPUC sets new electric rates for PG&E and Edison
    customers", May 15, 2001, Docket Nos. A0010028, A0011038, A0011056,
    Decision 01-03-082, March 27, 2001.

[^21]: CPUC, "CPUC Directs Rapid Deployment of low-income assistance
    programs," May 3, 2001, Docket No. A0011-009, Decision 01-05-033.

[^22]: AARP Comments, CPUC, [Joint Commissioners' Ruling on Automatic
    Enrollment Dated June 14, 2001]{.underline}, Docket R-98-07-037,
    June 29, 2001.

[^23]: An Act Relative to Restructuring the Electric Utility Industry in
    the Commonwealth, Regulating the Provision of Electricity and Other
    Services, and Promoting Enhanced Consumer Protections Therein, House
    No. 5117, November 19, 1997.

[^24]: G.L. c. 164, \'1B(d) and implemented in the Massachusetts DTE
    regulations, 220 C.M.R. \'11.04.

[^25]: .Massachusetts DTE, [Letter to Massachusetts Electric Company
    regarding Pricing for Default Service,]{.underline} June 1, 1999.

[^26]: .[Order Instituting a Notice of Inquiry/Generic Proceeding into
    the Pricing and Procurement of Default Service]{.underline}, D.T.E.
    99-60, June 21, 1999.

[^27]: . [Ibid,]{.underline} Order at 2.

[^28]: . Massachusetts DTE, [Investigation by the DTE on its own Motion
    into the Pricing and Procurement of Default Service Pursuant to G.L.
    c. 164, \'1B(d)]{.underline}, Order, DTE 99-60-B, June 30, 2000.

[^29]: . [Order Addressing Recommendation of the Working Group on
    Default Service Issues,]{.underline} DTE 99-60-C, October 6, 2000.

[^30]: . Ibid.[, at 10.]{.underline}

[^31]: . Re: Standard Offer Service Fuel Adjustments, DTE 00-66, 00-67,
    00-70, December 4, 2000. The consumer organizations complained that
    this decision had been reached without the development of record
    evidence as to the fuel procurement practices of the utilities, but
    did not object to the Department=s analysis of the legislation and
    the ongoing deferrals of fuel costs. Whether or not the Legislature
    exempted fuel costs from the rate reductions, the public education
    materials by all parties never explained to the public that the rate
    decrease would be subject to reconciliation of fuel costs in the
    future. [See, e.g.,]{.underline} the DTE website explanation of
    Electric Restructuring in Massachusetts:
    [http://www.state.ma.us/dpu/restruct/competition/index.htm]{.underline}.

[^32]: While it has not been able to deliver lower priced electricity,
    the Compact has recently taken over the delivery of energy
    efficiency programs in its service area from the local utility
    (NSTAR) and has become a focal point for consumer advocacy in
    statewide policy debates.

[^33]: The Commission rejected Mass.Electric's proposal to offer a
    12-month fixed price option for Default Service in addition to the
    DTE-mandated six month option, stating that the six-month option
    sends the proper price signal to customers and that this should be
    accompanied by a renewed effort by the utility to market a 12-month
    budget billing plan to its customers. Letter Order, D.T.E. 99-60,
    MECo's Default Service Pricing, April 3, 2001.

[^34]: Many thanks to John Howat at the National Consumer Law Center,
    Boston, MA for the use of his graph.

[^35]: Order, Petition of Western Massachusetts Electric Co. for
    approval by the D.T.E. of a three-year Energy Efficiency Plan for
    2000-2002, D.T.E. 00-79, September 25, 2001.

[^36]: Massachusetts DTE, Order Opening Investigation into Competitive
    Market Initiatives, D.T.E. 01-54, June 29, 2001, at 1. This Order
    and the comments summarized in this section are available at the
    Massachusetts DTE website:
    <http://www.state.ma.us/dpu/electric/compmarketisu.htm>

[^37]: Order, D.T.E., 01-54-A, October 15, 2001,
    [http://www.state.ma.us/dpu/electric/01_54/1015order.pdf](http://www.state.ma.us/dpu/electric/01-54/1015order.pdf)

[^38]: D.T.E. 01-63, Cape Light Compact Default Service Pilot.
    Subsequent to the issuance of the Competitive Service order, the DTE
    issued an approval of the proposal by the Compact to seek bids for
    serving the 42,000 default service customers within its municipal
    service boundaries at rates that would be above the Standard Offer
    price, but below the local utility's Default Service price.

[^39]: This paper was, for the most part, written prior to the terrorist
    attacks on September 11, 2001, and does not reflect the effects of
    those attacks on New York. There has been a dramatic decrease in
    energy consumption in New York City since that event, which has no
    doubt contributed to lower wholesale market prices.

[^40]: . As of October 2000, only 175,196 residential customers had
    selected a competitive marketer or ESCO, 3.2% of the statewide
    total. By December 2000, the residential customer migration had
    increased slightly to 3.4% of all residential customers. By far the
    largest number are customers of Consolidated Edison (41%) and
    Niagara Mohawk Power (24%). The New York PSC publishes customer
    migration statistics at
    [http://www.dps.state.ny.us/Electric_RA_Migration.htm]{.underline}.

[^41]: .New York Public Service Commission, Case 96-E-0897, In the
    Matter of Consolidated Edison Co. of New York, Inc.=s plans for
    Electric Rate/Restructuring pursuant to Opinion No. 96-12, February
    28, 2000. See also Opinion 97-16 at 2, (ANew York City and
    Westchester consumers will receive lower average electric bills.@),
    15 (AFor all other customers, there wil be a 10% rate reduction
    phased in over the term of the Settlement.@), 26 (AThe 10%
    cumulative base rate reduction for commercial and residential
    customers is firm, and no longer dependent on future
    contingencies.@)

[^42]: . Office of the State Comptroller, New York, AElectric
    Deregulation in New York State: The Need for a Comprehensive Plan,@
    February, 2001, Chart C.

[^43]: . PSC data as summarized by the Public Utility Law Project in
    their comments on the PSC Price Spike Mitigation Proposals, see fn.
    42.

[^44]: . [Wall Street Journal]{.underline}, AMismanagement of NY Power
    Mkt Costs MillionsBUtilities,@ October 5, 2000,
    [http://www.interactive.wsj.com/archive/retrieve.cgi?id+DI-CO-200001005-006703.djml]{.underline}

[^45]: . See, Department of Public Service Pricing Team, [Interim
    Pricing Report on New York State=s Independent System
    Operation]{.underline}, December 2000; ACon Edison Asks FERC to
    Close Loopholes That Enable New York Generators to Exercise Market
    Power; Additional Price Protection for Customers and a More
    Competitive Marketplace Sought,@ Con Edison Press Release, March 2,
    2001; APSC Chair Announces Five Point Plan for Regional Energy
    Markets and Managing Demand for Electricity,@ PSC Press Release,
    February 20, 2001.

[^46]: . New York PSC, Case 00-M-0504, Proceeding on Motion of the
    Commission regarding Provider of Last Resort Responsibilities, the
    Role of Utilities in Competitive Energy Markets, and Fostering the
    Development of Retail Competitive Opportunities.

[^47]: .[Energy Competition Next Steps, Draft Phase I and II Consensus
    Report]{.underline}, Case 00-M-0504, January 2001.

[^48]: . Press Release, New York State Electric and Gas Co., ANYSEG
    Proposes Electric Price Protection Plan that Freezes Rates and
    Assures Energy Reliability,@ March 8, 2001,
    [http://www.nyseg.com]{.underline} .

[^49]: Banerjee, Neela and Perez-Pena, Richard, "Power Politics: A
    Failed Energy Plan Catches Up to New York," [New York
    Times]{.underline}, June 1, 2001.

[^50]: See, e.g., H. Carl McCall, New York State Comptroller, "Electric
    Deregulation in New York State: The Need for a Comprehensive Plan,
    Feb., 2001.

[^51]: New York State Transitional Energy Plan, 11 separate pieces of
    legislation. These bills are summarized and links to the bills
    themselves are provided at
    [http://www.pulp.tc.](http://www.pulp.tc./)

[^52]: New York PSC, May 2001 Electric Retail Access Migration Summary,
    <http://www.dps.state.ny.us/Electric_RA_Migration.htm>

[^53]: AARP and the Public Utility Law Project (PULP) and others
    petitioned the PSC to initiate a proceeding to investigate rates
    charged by Con Edison in 2000, but the Commission denied that
    petition on May 2, 2001. New York PSC, Order Denying Petition, Case
    00-E-1750.

[^54]: New York PSC, [Order Concerning Sharing Mechanism and Directing
    Filing of Tariff Amendment]{.underline}, Case 96-E-0897, July 18,
    2001.

[^55]: FERC finally approved a "circuit breaker" or automated mitigation
    procedure for NYISO in late June 2001. When bids on the day ahead
    market exceed \$150 per MW hour, an automatic review occurs to
    prevent a generator from withholding capacity to drive up prices.
    This mechanism is separate from the wholesale price of power, which
    is capped at \$1,000 per Mwh throughout the Northeast.

[^56]: Consolidated Edison provides price comparisons between its own
    prices and suppliers offering service in its territory at
    <http://www.energyguide.com/finder/welcome.asp> By the fall of 2001,
    prices offered by alternative suppliers (many of whom were offering
    fixed rates) were uniformly higher than the default service provided
    by ConEd, due to the drop in wholesale market prices compared to
    ConEd's estimates.

[^57]: Recommended Decision, [Proceeding on Motion of the Commission
    Regarding Provider of Last Resort Responsibilities, the Role of
    Utilities in Competitive Energy Markets, and Fostering Development
    of Retail Competitive Opportunities]{.underline}, Case 00-M-0504,
    July 13, 2001.

[^58]: Recommended Decision, fn.87, at 46.

[^59]: NYSEG, "New York State's Electric Energy Crisis and New York
    State Electric &Gas Corporation's Comprehensive Solution", April
    2001, available at [http://www.nyseg.com.](http://www.nyseg.com./) .

[^60]: ^?^ Electric Generation and Customer Choice Competition Act
    (1996), 66 Pa. C.S. \'\'101, et seq.

[^61]: . PennFuture, a Pennsylvania public interest organization, has
    monitored the development of the Pennsylvania energy markets
    closely. See http://www.pennfuture.org

[^62]: .Pennsylvania PUC, Final Order, [Guidelines Addressing Return of
    Customers to Provider of Las Resort Service]{.underline}, Docket No.
    M-00960890F0017, June 22, 2000.

[^63]: . Pennsylvania PUC, [Joint Petition for Full Settlement of PECO
    Energy Company=s Restructuring Plan and Related Appeals and
    Application for a Qualified Rate Order and Application for Transfer
    of Generation Assets]{.underline}, Docket No. R-00973953, Order
    Approving Settlement, May 14, 1998, Issue L, Paragraph 38.

[^64]: .Another provision of CDS requires that a supplier must provide
    at least 2% of its offered energy supply for CDS service from
    renewable resources in order to be a qualified bidder. This
    increment must increase annually by .5%. The Commission can reduce
    this requirement if the cost of power from the renewable resources
    increases the cost of the entire block by more than 2% over what the
    power would cost without the renewable requirement.

[^65]: .Annex A, PECO Energy rules for Competitive Default Service,
    February 28, 1999, Q.7(b).

[^66]: .Pennsylvania PUC, [Application of PECO Energy Co., Pursuant to
    Chapters 11,19,21 and 28 of the Public Utility Code, for Approval of
    a Plan of Corporate Restructuring\...,]{.underline} Order, Docket
    No. A-110550F0147, June 22, 2000. As part of the merger settlement,
    the transmission and distribution rate cap was extended until
    December 2006.

[^67]: .Pennsylvania PUC, [PECO Energy Co. Competitive Default Service
    Program Bidding: Joint Approval of Competitive Default Service
    Coordination Agreement]{.underline}, Order, Docket No.
    A-110550F0147, November 20, 2000.

[^68]: As of July 1, 2001, three competitors remained in GPU Energy's
    service territory, servicing 4,800 customers. This is a 90% drop
    from the 47,000 customers who were buying electricity from
    competitors on April 1, 2001.

[^69]: Office of Consumer Advocate, PA Electric Shopping Statistics,
    July 2000 and October 2001. Available online:
    [http://www.oca.state.pa.us](http://www.oca.state.pa.us/cinfo/instat.htm)

[^70]: The PUC's decision, the settlement, and a press release about the
    GPU merger decision is available on the PUC's website:
    <http://puc.paonline.com/>

[^71]: Fitzpatrick, T., "Electricity Competition is the Keystone State,"
    [Public Utilities Fortnightly]{.underline}, October 15, 2001, at
    14-16.

[^72]: . Senate Bill 7, amending the Public Utility Regulatory Act
    (PURA), \'\'39.101, et seq.

[^73]: The PUC set the Price to Beat rates in December 2001 and
    reflected a greater than 6% rate decrease for most utilities to
    reflect recent price drops in natural gas. For example, the average
    cents per kWh for Reliant Energy was reduced 17%, from 10.40 cents
    to 8.62 cents per kWh. This rate is all inclusive of distribution,
    transmission and energy charges. Overall, rates were reduced from an
    average of 8.5 cents per kWh in effect in late 1999 to 8 cents per
    kWh on 1/1/02.

[^74]: ERCOT in fact switched 67,000 customers during the pilot program
    and has stated that it can now switch at least 15,000 switch orders
    per day. See the ERCOT website for further information:
    [www.ercot.com](http://www.ercot.com/)

[^75]: The Commission has delayed retail competition for those non-ERCOT
    utilities serving areas in northern Texas and southeastern Texas
    (Entergy, Southwestern Electric Power or Swepco).

[^76]: <http://www.puc.state.tx.us/about/oversight/EURLOC.pdf>

[^77]: Under Texas price disclosure rules, REPs must factor in the
    effect of both fixed and variable charges in calculating the average
    cents per kWh for Electricity Facts Labels. As a result, a REP that
    charges a fixed monthly fee in addition to what appears to be a low
    cents per kWh energy charge may end up costing the customer more
    than the Price to Beat rates, particularly for low usage profiles.

[^78]: Energy America has entered into consent decrees in New Jersey and
    Georgia concerning allegations that its marketers deceived customers
    into believing that it was the utility or that customers had to
    choose a marketer or go without electricity or natural gas in the
    newly competitive market.

[^79]: This Chart was presented by Commissioner Perlman at a conference
    in Austin, TX on February 26, 2002, but the "apples to apples"
    comparisons are not otherwise available on the PUC's website.
    Instead, the PUC website provides POLR rates as energy only (without
    the T&D portion) and the Price to Beat Rates are presented as
    all-inclusive rates.

[^80]: See <http://www.puc.state.tx.us/rules/rulemake/25360/25360.cfm>
    for the Staff Strawman Proposal and schedule for this proceeding.

[^81]: Section 25.454 (c) of PURA authorizes the Rate Reduction Program
    and Section 25.453(f) authorizes a Targeted Energy Efficiency
    Program. These programs are funded by means of a System Benefit
    Charge imposed on all customer classes. The Commission approved a
    non-bypassable fee of \$.65 per MWh for FY 2002 (total of \$62.3
    Million) to be charged as part of the transmission and distribution
    utility nonbypassable charges. See
    <http://www.puc.state.tx.us/electric/projects/24116/24116.cfm> for
    further information on the funding orders.

[^82]: In mid-January, low-income advocates alleged that 500,000
    eligible customers were not receiving the discount because of
    computer snafus and delays.

[^83]: . Amended Substitute Senate Bill No 3, 123^rd^ General Assembly,
    eff. October 5, 1999.

[^84]: .Sec. 4928.34 and 4928.40.

[^85]: . Rule 4901:1-10-32 and 4901:1-21-16, Ohio Administrative Code.

[^86]: . Ohio PUC, In the Matter of the Application of FirstEnergy Corp.
    on Behalf of Ohio Edison Co., The Cleveland Electric Illuminating
    Co., and The Toledo Edison Co. for Approval of their Transition
    Plans and for Authorization to Collect Transition Revenues, Case No.
    99-1212-EL-ETP, Opinion and Order, July 19, 2000.

[^87]: .Sec. 4928.14.

[^88]: . An Act to Restructure the State=s Electric Industry, P.L. 1997,
    ch. 316 (codified as Chapter 32, of Title 35-A, M.R.S.A.
    \'\'3201-3217).

[^89]: . The California statute did not require divestiture, but there
    were economic incentives if a utility divested its fossil fuel
    generators. Pennsylvania=s statute prohibited the PUC from requiring
    divestiture.

[^90]: . Chapter 301, Standard Offer Service, eff. July 31, 1999.

[^91]: .[Order Designating Standard Offer Provider and Rejecting Certain
    Bids (CMP)]{.underline}, Docket No. 99-111, December 3, 1999. The
    successful bidder was Energy Atlantic, an affiliate of Maine=s
    smallest investor-owned utility, Maine Public Service Co.

[^92]: Maine PUC, Order Designating Standard Offer Provider and
    Directing Utilities to Enter Entitlements Agreements, Docket No.
    2001-399, October 2, 2001. The Maine PUC publishes the Standard
    Offer rates for all Maine utilities on its website:
    <http://www.state.me.us/mpuc>

[^93]: . Bill 5005, An Act Concerning Electric Restructuring, Public Act
    98-28.

[^94]: . Docket No. 99-03-36, DPUC Determination of The Connecticut
    Light and Power Co. Standard Offer, October 1, 1999 and December 15,
    1999; Docket No. 99-03-35, DPUC Determination of United Illuminating
    Co. Standard Offer, October 1, 1999.