**DEFAULT SERVICE:**

**CAN RESIDENTIAL AND LOW INCOME CUSTOMERS BE**

**PROTECTED WHEN THE EXPERIMENT GOES AWRY?**

Barbara R. Alexander

Consumer Affairs Consultant

15 Wedgewood Dr.

Winthrop, ME 04364

(207)395-4143

E-mail: [barbalex@ctel.net]{.underline}

April 2001

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). Her clients include national
consumer organizations, state public utility commissions, and state
public advocates.

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 report is to summarize and make some preliminary
conclusions about the development of a default or provider of last
resort service for residential and small commercial customers as part of
the move to retail electric competition. 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.

[Organization of the report.]{.underline} The first part of this report
describes why Default Service is an important policy decision with
implications for the ability of residential and low income customers to
maintain a reasonably priced electric service. Preliminary observations
and recommendations based on the analysis contained in Part II of this
report are presented. Part II describes the individual state Default
Service policies and programs for key states or those where significant
implementation activity has occurred. This report does not summarize
developments in every state that has moved to retail electric
competition, but it does concentrate on those states that have actually
moved to implementation of retail competition and Default Service or
where substantial controversy has surrounded the decision concerning
Default Service. Specifically, the following states are highlighted in
this report:

California

Pennsylvania

Massachusetts

Maine

New York

Connecticut

Nevada

Texas

Ohio

The legislative directives and regulatory implementation activities with
respect to Default Service for each state are identified. Where
information is available about impacts (participation levels, price
changes, development of low income rates or discounts) on residential
customers or low income customers, that information is presented.

[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, who is unable to
obtain competitive electric service, whose competitive service is
cancelled, or whose supplier is unable to provide service. 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 commission. 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 continue to receive an
essential service at a regulated price.[^2]

Second, utilities and some policymakers have argued, successfully in
many states, that lower use customers are not seeking to move to
alternative providers for electricity and are unlikely to benefit from a
competitive energy market in the form of lower prices, at least in the
early days of the development of the competitive market. Therefore,
these customers are unlikely to seek alternative suppliers and
alternative suppliers are unlikely to target such customers. That these
arguments are also self-serving in that they result in utilities
retaining a huge volume of customers without additional costs has not
been lost on most observers, but has not changed the ultimate result.

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 red-lining 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 suffer an adverse credit history.

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. 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 maintain 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 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 the full scale implementation of retail competition has not
yet occurred. An exception may be Pennsylvania, where the highest levels
of residential customer shopping has been recorded of any state that has
adopted full scale retail electric competition. Even in Pennsylvania,
however, the percentage of customers who are shopping varies widely from
16% in PECO Energy's service territory to less than 1% in Allegheny
Energy's.[^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.

PRELIMINARY CONCLUSIONS AND OBSERVATIONS

While electric restructuring is still in a stage of transition in most
states that have adopted this approach, the experience highlighted in
this report suggest both why the nature and price of Default Service is
paramount for residential and low income customers and what statutory
models might work best at achieving a stable and reasonably priced
Default Service:

1.  With few exceptions, Default Service is provided by the incumbent
    utility and that utility is responsible for obtaining the generation
    service either from its own generating facilities or via contracts
    in the wholesale market. Only in California and in New York
    (Consolidated Edison) were the utilities required to provide this
    service by obtaining spot market power from the wholesale market and
    passing through this service to retail customers. Other states
    allowed utilities to use pre-restructuring methods of providing
    generation service, either through native generation units or long
    term contracts. The use of the competitive bid process supervised by
    the state commission in Maine and Pennsylvania (Competitive Default
    Service for some customers) was adopted as a means of opening up the
    competitive market and attracting new suppliers to the competition
    program for residential customers, as well as obtaining a lower
    price than the embedded cost of generation provided by the incumbent
    utility. Even where the state has mandated competitive bidding with
    some supervision of this process by the state commission, the
    utility continues to bill for this service and the only change is
    that the customer's bill names a specific Default Service supplier.

2.  Default Service has typically been structured 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 preserved the intra-class allocation of class
    responsibility for the utility's 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. However, such an approach would shift
    costs to lower use customers and result in higher monthly bills in
    most cases for lower use customers. Rather, state regulators (often
    as a result of Legislative declarations) have implemented rate caps,
    rate freezes, or rate decreases using the current rate design so
    that residential customers will not see any detriment as a result of
    the move to retail competition.

3.  Default Service is typically accompanied by the traditional utility
    protections that already apply to regulated services, such as
    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, there is no sanctioned degradation of service
    quality or consumer protection as a result of the move to retail
    competition for customers on Default Service. Obviously, this policy
    approach is easier to maintain when the default provider is the
    incumbent utility, even if the generation portion of the bill is
    obtained via competitive bid, because of the close connection
    between these policies and programs and the issuance of the monthly
    bill and its collection. This approach bodes well for low income and
    other payment troubled customers.

4.  To date, most states have not isolated or segregated low-income or
    "payment troubled" customers compared to other residential customers
    in the provision of Default Service. As a result, the cost to serve,
    bill, collect, and interact with payment troubled customers has been
    integrated into the rates charged for all residential customers. At
    least in the short run, the concern of many low income advocates
    that market segmentation would result in higher priced electric
    service for certain residential customers has not occurred. The
    attempt to carve out a means to provide higher cost Default Service
    to low income or credit challenged customers in Nevada was roundly
    criticized and withdrawn.

> On the contrary, most states have significantly expanded universal
> service programs and targeted bill payment assistance and energy
> conservation/weatherization programs to low income customers.
> Pennsylvania has quadrupled the size and budgets for its low income
> programs. Other states have created new programs targeted to low
> income customers that are funded through the regulated distribution
> portion of the bill.
>
> As long as there are a substantial number of residential customers
> receiving Default Service, for any reason, the higher costs associated
> with serving customers who need more attention in the form of payment
> arrangements and payment difficulties will be spread among all
> residential customers or included in distribution (regulated) utility
> rates. This approach seems to provide the highest possible level of
> protection, but does not bode well for the future if a competitive
> market does develop and most residential customers enter the
> competitive market. As the size of the default pool lessens to those
> who are unable to obtain service in the competitive market (as opposed
> to those who do not choose to shop for electricity), the ability to
> create a reasonably priced Default Service option for payment troubled
> or credit challenged customers is diminished. The more segmented this
> market becomes, the more likely that Default Service will be priced
> [higher]{.underline} than that available in the competitive market if
> customers can pay their monthly bill on time and do not need more
> expensive customer care in the form of payment arrangements, medical
> emergencies, collection notices, and contract termination procedures.
> Because of the existence of legislatively mandated rate caps or
> protections during the transition period in most states, as well as
> the lack of the development of a vibrant and competitive market for
> residential customers, this legitimate concern is not yet apparent.

5.  While most states adopted what appeared be be a cap or freeze on
    rates for a transition period, some states have not protected
    customers from increases in Default Service prices when the
    wholesale market has experienced volatile shifts in prices and sharp
    price increases. Massachusetts has interpreted the legislatively
    mandated rate cap or rate reduction as not including increases that
    reflect fuel or purchased power costs incurred by the utility in the
    wholesale market. Maine's restructuring statute did not include a
    rate freeze or price cap and has approved the pass through of higher
    Standard Offer rates for some utilities. Other restructuring
    settlements, such as those approved by the New York PSC for
    Consolidated Edison and the Massachusetts electric restructuring
    legislation, both appeared to offer customers a rate decrease, but
    the fine print allowed the pass through of actual market power
    prices. Finally, the California Commission has approved rate
    increases on two occasions in the January-March 2001 period for two
    electric utilities that was not contemplated when retail competition
    was adopted due to the pressures from the higher market prices for
    electricity that utilities have been obliged to pay for Default
    Service power.

> However, these experiences should be contrasted with that in
> Pennsylvania where the generation and T&D rate caps have so far
> "worked" to shield residential customers from any significant
> volatility in the wholesale market. Only one Pennsylvania utility (GPU
> Energy) has sought to evade the mandated rate caps, but that
> proceeding has been linked to the filing by the utility for approval
> of a merger with a large Ohio utility, FirstEnergy. Furthermore,
> Connecticut and Ohio have adopted firm rate caps for both distribution
> and generation Default Service for the transition period. As a result,
> there is experience that demonstrates that residential customers can
> be provided with rate decreases or rate caps, and the opportunity to
> shop for lower prices in a competitive market IF the wholesale market
> is relatively stable and utilities do not incur risks that threaten
> their economic viability.

6.  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
    been successful. The one bid for residential customers that was
    accepted in Maine was tied to the use of certain purchased power
    contracts that made the bid viable. Several Pennsylvania utilities
    (GPU Energy, Duquesne Light) have sought to bid out 20% of their
    non-shopping residential customers, but no competitive bids
    submitted. The recent PECO Energy competitive Default Service was
    awarded by a negotiated contract. While Maine did not have a rate
    cap in place, the Commission has refused to accept some bids that
    would have resulted in higher fixed rates over the 1-2 year bid
    period. Suppliers have argued in these states that the "price to
    compare" or the current rate was too low or that certain contract
    terms (fixed price, contract term, billing and collection
    restrictions) made the proposal economically unviable. As a result
    of this experience, 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 in these bid programs.

7.  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)[^4] 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." According to NEMA,
    Default Service should not be used to address low income needs, but
    rather specific programs directed to low income customers should
    address these needs. Under the NEMA approach, default service should
    be designed as a short term transition mechanism that minimizes the
    use of this service over time. For example, NEMA has opposed the New
    York State Electric and Gas Co. (NYSEG) proposal to adopt long term
    stable rates for Default Service provided by the utility on the
    basis that it "\...is an outrageous attempt to circumvent multiple
    Commission orders and precedent on issues including properly
    structured back out credits, the Provider of Last Resort function,
    the utilities exit of the merchant function, competitive provision
    of billing and metering, and uniform business practices."[^5] 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."[^6]

> Any approach that seeks to pass through market-based prices to
> residential customers will increase price volatility due to the
> "abnormalities" that have occurred and that are likely to continue to
> occur in the infancy of the wholesale market and the development of
> regional transmission organizations. Whether states and state
> regulators will be pressured to ease up on promises of lower rates to
> mass market customers and either roll back or "reinterpret" rate caps
> and rate freezes remains to be seen. Clearly, there is a growing
> disconnection between the promises that state legislators and
> regulators have presented as the basis for the move to retail
> competition and the actual prices that the wholesale market is
> pressing to send through to retail customers. Furthermore, the move to
> competition has transferred the power to set rates for retail
> customers from the state regulators to FERC because of the growing
> importance of the operation of the wholesale market in the
> establishment of retail prices. When generation is no longer owned by
> the utility that has a state franchise and obligation to serve, state
> regulators 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
> 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.

8.  In contrast to those who seek more price volatility and market based
    rates for Default Service, many states have pulled back or delayed
    the move to retail competition as a result of the volatile prices
    that have been widely reported in California and New York. Such
    states include Nevada, New Mexico, Oklahoma, Montana, Arkansas,
    North Carolina, Minnesota. Clearly, state policy makers and
    legislators strongly resist putting the vast number of consumers at
    risk for [higher]{.underline} or [volatile]{.underline} prices for
    electric service as the price for moving to retail competition.
    Therefore, if the proponents of competition are to be successful in
    their advocacy, it appears that a stable and fixed price Default
    Service program will have to be considered as a key element in the
    public acceptability of the transformation of an industry.

9.  Finally, in most states Default Service, at least with respect to
    its provision by utilities under rate caps or freezes, is a creature
    of a specific transition period. This period varies from 2-3 years
    to 9-10 years. This period is often linked to the recovery period
    for Stranded Costs. Those states in which transition periods are
    relatively short (e.g., Maine, Connecticut, Massachusetts, New
    Jersey, California) will face the necessity of identifying the
    provider of Default Service and the method by which that service is
    priced within the next 18 months. The volatility of the wholesale
    market that is projected to occur this summer in New England, New
    York, PJM, and Western markets does not bode well for any state
    regulator's ability to establish a pricing mechanism for residential
    customers on Default Service that will reflect either the
    traditional residential rate design or rate stability. States may be
    forced to consider more frequent price changes or rate designs that
    reflect seasonal price spikes. These changes may result in further
    state legislative questions about the move to retail electric
    competition or attempts to roll back a state's prior adoption of
    retail competition[^7] or extension of rate caps and regulation of
    Default Service.

DEFAULT SERVICE: A SUMMARY OF STATE ACTIVITY

**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,[^8] 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 is subject to
more significant variation between the summer and winter months. During
the transition period when utilities are collecting stranded costs, this
volatility in 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 must be 10% lower during
the transition period. It was expected by the Commission and the
utilities who endorsed the restructuring plan that the cost of power
would in fact drop and that the utilities would use the differential
between the actual costs and the price billed to customers to pay off
their stranded costs.

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. Low income customers are
served as part of the residential class in general, but qualified low
income customers have access to a 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.

A residential Default Service customer in California[^9] receives a
monthly bill which states the unbundled energy costs and then breaks
down the total electricity charge into the following components:

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

-   PX Energy Charge: "The 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 shops for electricity and selects a competitive provider,
the bill will 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 has to sell generation service at a retail price than is less
than the wholesale spot market price passed through by the utility. This
exercise is made in even more difficult for the supplier because the
utility's PX charges will vary every month to reflect the market
wholesale price, but this volatility is masked by the overall 10% rate
reduction. As a result, competitive providers are not able to market the
sale of generation in a manner that allows a customer to compare the
price of generation that appears on the utility's monthly bill. No
matter what price is stated for PX Energy on the customer's bill, the
total bill will reflect a 10% rate decrease during the transition
period. Suppliers would have to offer a product that beat the monthly
wholesale price and cannot do so by offering a fixed price or "hedged"
price because the customer's bill is held steady no matter how volatile
the market operations. 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. When this occurred, no
later than April, 2002, the 10% rate reduction would disappear and the
actual monthly PX price adjustment would appear on the customer's bill.
Therefore, if there were no change in the cost of generation in the
wholesale market from the initiation of competition in March, 1998
through March 2002, all residential rates would increase at least 10%
due to the end of the mandated rate reduction. However, at least 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.[^10] However, the potential
volatility associated with the expected 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.

In fact, the Commission strongly supported the notion of "accurate price
signals" in a related decision: " 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."[^11] 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 were labeled a
"crisis" and 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 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 time 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 have filed
for permission to halt the transition rates and charge higher rates,
claiming that stranded cost recovery has been completed early. Both have
sought to change their rate design so that customers pay higher flat
rate charges for distribution service. 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.[^12] 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. Since January, the State has
spent about \$50 million per day to buy power for the utility customers
and has 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 guarantees that the State
will provide the major role in the purchasing of electricity for many
years. Under this legislation[^13], the State is 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 State 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. Neither the Legislature nor the Commission
has yet addressed this \$12 billion deficit, but Governor Davis has
entered into negotiations with the utilities that will focus on the
State's purchase of the transmission system, the payment of which would
be used by the utilities to pay for power bought prior to January, 2001
when the State began to purchase power directly for utility customers.
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.[^14]

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 over the
coming months. Unfortunately, the final result is likely to include
higher energy charges for 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 have sought to enter the
wholesale market to buy power for their customers and found a power
shortage or 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
have filed for rate increases with their respective state commissions.

The impact in Montana is particularly adverse. Montana adopted retail
electric competition in 1997.[^15] 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 variable priced power. 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 recent survey of industrial customers in
Montana has 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, electricity rates in Montana
have increased tenfold.[^16] As a result of these developments, the
onset of retail electric competition for residential customers has been
delayed from July 1, 2002 until at least July 2004. This delay, an
option given to the Montana PSC in that state's restructuring
legislation, will continue the distribution utility's obligation to
serve and the Commission's ability to oversee rates for the total
electric bill.

As of March 2001, residential customers in California have seen rate
increases that vary from about 9% for customers of SCE and PG&E. These
rates are now scheduled to increase by 30-40% beginning in May 2001.
SDG&E residential customers still pay 6.5 cents per kWh. Most observers
have assumed that all customers will see another 10% rate increase at
the statutory end of the transition period in April 2002, if not sooner.
Further rate increases may also be ordered.

**Pennsylvania.** The Pennsylvania restructuring legislation[^17]
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 Default Service is
closely related to 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 "the
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 restructuring 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 "real" 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 ("shopping credit") that complied with the statutory
rate caps and that was 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 have switched to alternative
suppliers, of which 473,852 are 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[^18] 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. In PECO Energy's service territory, 80,000 low income
residential customers are on a discounted rate program funded through
distribution rates.

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 "marketing" 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 "dumped" customers onto
POLR service when prices in the wholesale market increased in the summer
of 2000, the Commission issued an Order[^19] 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 statutory requirement that the utility provide such service. In
the GPU Energy, PECO Energy, and Duquesne Light Co. 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.
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 "assigned 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."[^20] This service is referred to as Competitive Default
Service (CDS).[^21] Any bid must comply with the generation rate cap
that would otherwise be applicable to PECO Energy. Furthermore, the CDS
provider may, at the customer's option, provide a single bill to the
customer which would be issued by the supplier and contain all the
regulated utility charges. In doing so the CDS provider must provide all
the relevant 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.**[^22]
>
> **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 "exact
> 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 "stranded
> 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
and Duquesne Light later that summer, was unsuccessful in attracting
bidders for this service. In the Commission's approval of PECO Energy's
merger with Unicom in June 2000, however, it accepted a stipulation[^23]
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. As a result, the Commission
approved[^24] an agreement entered into by PECO Energy and New Power
Company, Inc. that will become effective April 2001. At that time 20% of
PECO's residential customers who have not yet chosen a competitive
supplier will be served by New Power, but PECO Energy will continue to
bill and collect the total bill. Customers served by New Power will
receive a 1-2% discount off the current PECO shopping credit (price for
generation service under the capped rates).

The only cloud on the sunny sky of customer savings and stable Default
Service prices has been the petition by GPU Energy to alter its
restructuring plan and allow its two electric distribution utilities
(Metropolitan Energy and Pennsylvania Electric Co.) to institute a
deferral tracking mechanism to reflect higher than expected wholesale
energy prices. GPU Energy is one of only two Pennsylvania utilities that
elected to divest its generation plants as part of the move to retail
competition. Its restructuring settlement also includes provisions to
comply with the statutory rate caps and the use of the competitive
Default Service bidding procedure. That process did not result in any
acceptable bids in early 2000. This petition is likely to be considered
in the context of GPU Energy's petition to merge with First Energy,
presently pending before the Commission. On January 19, 2001, the
Chairman of the PUC issued a press release which criticized GPU Energy
for deliberately alarming consumers and elected officials by suggesting
the energy crisis crippling California could easily affect Pennsylvania.
The Chairman stated, "I am outraged that GPU would even hint that a
similar energy crisis could happen to Pennsylvania. This appears to be a
thinly veiled attempt to influence a decision pending before the
PUC."[^25]

**Massachusetts:** The Massachusetts restructuring statute[^26] creates
two services: Standard Offer Service and Default Service.[^27] 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 are not able to
receive this service, and existing customers may enter the competitive
market and return once within 120 days, but such customers 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.

Full retail competition was initiated in March 1998, but very few
customers have switched and few alternative suppliers have solicited
customers because the regulated Standard Offer Service (SOS) as
reflected by the generation charge that appears on unbundled customer
bills was priced below the wholesale market price of electricity.
Standard Offer rates for residential customers gradually increased, from
3.2 cents per kWh in 1998 to 4.5 cents in 2000 at Boston Edison Co., and
from 3.2 cents per kWh to 5.401 cents at Massachusetts Electric. Unlike
Pennsylvania, Massachusetts did not unbundle the pre-competition bill in
a manner that produced shopping credits that were higher than the
current retail electricity prices. Even with the gradual increase in SOS
prices, however, the wholesale market saw even higher price increases
throughout 2000. As of November 2000, only 2,848 residential customers
had switched.

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 "qualified" for
Default Service pricing, primarily because they had moved to a new
location since March 1, 1998. Unlike SOS, however, the price for Default
Service must not exceed the "monthly market price for electricity."
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 that utilities should provide those
eligible for Default Service with the Standard Offer price.[^28]
However, the DTE initiated a proceeding to implement the market price
requirement for Default Service in June 1999.[^29] The Department noted
that " . . . 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."[^30] 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.[^31] The Department ordered utilities to offer a fixed-price,
six-month Default Service that will be obtained by bids in the wholesale
market. Residential customers who must obtain Default Service will be
automatically placed on the fixed price rate, but will be offered a
month-to-month variable price for this service as well. Commercial and
industrial customers will be put on the variable price option. 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 the 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[^32], 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 "send an efficient price signal."[^33]

The new Default Service rates are effective 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 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[^34], 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.

As a result of this decision, SOS prices increased effective January 1,
2001. The following chart shows the increases in SOS and Default Service
prices (cents per kWh) for selected Massachusetts electric utilities for
residential customers:

+-------------------+---------+---------+---------+--------+---------+
| Utility           | 19      | 19      | 20      | 200    | 2001\-- |
|                   | 98--SOS | 99--SOS | 00--SOS | 1--SOS |         |
|                   |         |         |         |        | Default |
|                   |         |         |         |        | Service |
+-------------------+---------+---------+---------+--------+---------+
| Boston Edison     | 3.2     | 3.69    | 4.5     | 6.215  | 7.032   |
+-------------------+---------+---------+---------+--------+---------+
| Commonwealth      | 2.8     | 3.5     | 3.8     | 5.121  | 6.985   |
| Electric          |         |         |         |        |         |
+-------------------+---------+---------+---------+--------+---------+
| Mass. Electric    | 3.2     | 3.707   | 3.8     | 5.401  | 6.37    |
+-------------------+---------+---------+---------+--------+---------+

In other words, since the onset of restructuring, residential customers
on SOS in Boston have seen a 48% increase in the price of the generation
portion of the customer's electricity bill. Newcomers to Boston who must
obtain Default Service paid SOS prices in 1998-2000, but beginning in
2001 have seen a 54% increase. These increases have erased the rate cuts
that originally accompanied electric restructuring. Mass Electric
customers will see the largest increase, about 12% of the
[total]{.underline} electric bill for a customer who uses 175 kilowatt
hours and 17% for 750 kWh usage. The impact of this change on low-income
customers has been to erase the effect of the low income rate discount
in some cases, or substantially reduce the effectiveness of that
discount.

**Maine**: The Maine restructuring legislation[^35] has taken the
boldest step in the elimination of the current utilities from the retail
sale of generation service. Utilities were required to divest[^36] their
key generation sources and the Standard Offer Service was mandated to be
obtained by means of a competitive bid. 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 closely
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 "price to
compare" for customers contemplating a move to the competitive market.

Pursuant to the Commission's rules,[^37] 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. Rates must be submitted by bidders 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 which 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 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.[^38] This has been widely viewed as a relatively low
price which is likely to lessen marketer interest in competing for
residential customers. The successful bidder offered this fixed rate for
two years which was accepted by the Commission. 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. 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) will see stable rates that remain
below wholesale market rates until at least March 2002. There are
growing concerns about the impact of the wholesale market on commercial
customers and the looming impact on all residential customers next year
by policymakers. On March 20, 2001, the Senate Majority Leader of the
Maine Legislature announced a proposal to form a study commission to
analyze the impact of retail electric competition on Maine and its
potential impact over the next several years.[^39]

**Connecticut:** Connecticut's restructuring legislation[^40] 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.[^41]

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 "get" 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.

**New York:** 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.[^42]

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 of 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.[^43]
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.[^44] This has resulted in a total bill rate of over 19
cents per kWh, an increase of about 4 cents per kWh sine 1999.[^45] The
resulting furor[^46] led to investigations that concluded that New
York's wholesale market was flawed and Con Edison publicly warned the
Commission that a "California-type" situation could result without
prompt action from both the New York PSC and FERC. Both the PSC and Con
Edison are seeking intervention from FERC to control prices on the
wholesale market.[^47]

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.[^48] The Staff was required to
issue a "strawman" proposal for POLR service in mid-January.[^49]
Options being considered by working groups include 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 "given" 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
"wires" only utility. Briefs have been submitted by the parties, 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.[^50]

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 Draft Consensus
Report recognizes the need for expanded and coordinated low income bill
payment and energy assistance programs, but no funding level has yet
been identified. The Report also recognizes that such programs could be
funded by means of a nonbypassable charge included in regulated
distribution rates.

In addition to its review of the entire electric competition program,
the Commission is considering methods to "mitigate" price spikes for Con
Ed customers for the upcoming summer in which a lack of adequate
generation supply is likely to result in higher power prices again.
While consumers are seeking "hard" price caps (equal to 19-20 cents per
kWh for the total bill), the Commission's Staff has proposed temporary
rate caps that would merely defer excess prices for later recovery from
customers. [^51]

At least one other utility, New York State Electric & Gas Corp. (NYSEG),
has filed a proposal with the PSC that includes a 7-year price
protection plan for its customers. This proposal includes a fixed rate
that would be frozen for 7 years with no market pass through based on
fuel costs or the operation of the wholesale market.[^52] Of course,
NYSEG, unlike Con Ed, has not sought to divest its generation
facilities.

**Nevada:** Nevada is one of the few states that contemplates that the
competitive energy provider (referred to in Nevada as the "alternative
seller") selected by a customer after the start of retail electric
competition will have the sole billing and customer service relationship
with the customer. Under this "Single Retailer Model" the alternative
seller obtains regulated distribution services from the local utility on
behalf of the customer and assumes the sole point of contact for billing
for all electric services. Such an approach has also been adopted in the
Atlanta Gas Light natural gas competition program and in the State of
Texas for retail electric restructuring. The basic motivation of the
supporters of this approach is to prevent the local utility from
maintaining its market share and incumbent provider status. The
supporters of this approach also typically oppose allowing the utility
to serve as the Default Service provider.

Nevada's original restructuring legislation[^53] required the Commission
to designate a "vertically integrated electric utility" to provide
Default Service, but also allowed the Commission to prescribe
alternative methods, including direct assignment of customers to
competitive providers or the use of competitive bidding to select the
Default Service provider. In its first attempt at the implementation of
this provision, the Commission proposed a competitive bid process to
select the default provider for the start of retail competition with
features that were designed to stimulate a "high bid" approach by
competitive providers.[^54] Furthermore, the Commission's original
Provider of Last Resort proposed rule called for two Default Services,
one for customers who did not choose and one for customers who had a
poor credit history or who could not obtain service from an alternative
seller. The Commission proposed that the latter group of customers would
be identified by the utility based on recent payment history. These
credit risk customers would then be moved en masse to what the
Commission referred to as "Universal Last Resort Service." The price for
Universal Last Resort Service would be based on the costs associated
with serving this subset of the residential customer class. Obviously,
this customer group is likely to incur more costs relating to payment
arrangements, customer service, and bad debt expense, and, as pointed
out by the Consumer Advocate in Nevada in comments to the Commission,
the price for this service would likely be higher than for other
residential customers and so should be opposed as a violation of the
statutory rate cap and poor public policy. The Consumer Advocate
proposed a single Default Service provider for all customers: "The
single POLR model will assure that the costs of serving the entire
customer class will be spread among all customers who benefit from this
service, much as the cost of electric service today reflects the average
cost to serve each customer class."[^55]

The Legislature halted the Commission's proposal for the use of a
competitive bid and the designation of a Universal Last Resort
Service.[^56] These amendments also established a new rate cap for each
class of customers which expires on March 1, 2003 for POLR customers.
The new rate cap was set at a level not to exceed the total rate for
each class of customer that was in effect on July 1, 1999. While the
rate cap is in effect, the Commission cannot review the rates, earnings,
rate base, or rate of return of a designated provider of electric
service. In addition, the actual start date for retail competition was
pushed back from December 31, 1999 to March 1, 2000, or even later if
approved by the Governor.

Subsequent to this legislation, a global settlement was reached on the
pending merger between Nevada's largest investor owned electric
utilities and pending lawsuits that had been filed by both utilities
challenging restructuring orders of the Commission. Both utilities were
allowed to implement a monthly fuel clause adjustment beginning in the
fall 2000. This fuel adjustment is allowed to continue while the utility
serves as the POLR (through February 2003). However, in part as a
reaction to the wild swings in the wholesale market in California, the
Governor has further delayed the onset of retail competition
"indefinitely."

Prior to the Governor's decision to delay retail electric restructuring,
the Governor's Energy Policy Panel issued a report on January 11,
2001.[^57] The report appeared to contain a consensus that some form of
low income bill payment assistance and energy conservation and
weatherization assistance should be enacted as a condition of
implementation of retail competition. However, the report outlined a
variety of options for the timing and conditions for the implementation
of retail electric competition that revealed a lack of a consensus on
key matters. It would appear that retail competition, at least for
residential and small commercial customers, will be delayed until there
is more certainty concerning the availability of sufficient supply and
transmission facilities so as to avoid the rate shocks and volatile
markets experienced in California.

**Texas:** The Texas electric restructuring statute was enacted in
1999[^58] and calls for the implementation of electric competition for
all customers beginning January 1, 2002. The Texas industry model is
different than that adopted in most states, but has some similarities to
the Nevada approach. Under the Texas approach, customers will obtain
electricity service from "retail electric providers" or REPs. A REP will
have the sole contact and retail relationship with its customers and
will obtain the transmission and distribution services on a wholesale
basis from the former public utilities. The REP must handle all customer
contact and billing for the total electricity service. As of January 1,
2001, all customers will be switched to the affiliate REP of their local
electric utility or select an alternative REP. The affiliate REP must
provide service to all customers who are transferred to this service
under the "Price to Beat" rate, which will be 6% less than the rates in
effect in 1999. 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 entered the competitive market, albeit at a regulated rate. 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. The Commission is finalizing its rulemaking to define
the details of the Price to Beat rate, the conditions under which
residential and commercial customers can leave and return to this
service, and the conditions under which the rate can be adjusted to
reflect fuel cost changes.[^59]

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. It is the
POLR service that will provide service to all customers who cannot
maintain service in the competitive market after the end of the
transition period. 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 has issued final rules
that govern the bidding process for this service and sought bids
according to a Request for Proposals.[^60]

Pursuant to the Commission's rule, the POLR service will provide a
basic, standard retail service package to any customer no long served by
the customer's REP or whose REP defaults in its obligations to the
distribution utility or other license conditions.[^61] 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 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.

Because the bids for this service have not yet been made public, it is
not clear how this rate will differ from the Price to Beat that the
affiliate REP must offer in the transition period. However, the
Commission has retained the right to refuse all bids if they are not
"reasonable" and appoint a REP, including the affiliate REP, to act as
the POLR. It is possible, for example, that the Commission would appoint
the affiliate REP to act as the POLR provider at the Price to Beat rates
during the early years of retail competition. However, in the long run,
the POLR price will be based on the development of the electricity
market. Furthermore, the POLR service will eventually serve a pool of
customers who will not be able to maintain service from a REP or who has
been refused service by a REP. This is likely to result in a service
that will be somewhat higher than market rates or the Price to Beat. No
other state has created a Default Service approach that will isolate
payment troubled customers in such a fashion, although the ultimate
impact of such an approach will be masked in the early years of the
competition program due to the ability of customers to enter and leave
the Price to Beat service.

**Ohio:** Ohio also adopted retail electric restructuring in 1999, with
an implementation date of January 1, 2001.[^62] This legislation retains
the utility as the Default Service provider and establishes rate caps
for the "market 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 Commission had already approved rate
decreases or such decreases were scheduled to go into effect, the
restructuring statute preserved and mandates 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.[^63] 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.

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. This program, as well as increased energy efficiency
programs, will be funded by Riders that are included in regulated
utility rates and paid by all customer classes.

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 "opt 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.[^64] A municipality may also use the "opt 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 "opt
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 is scheduled to be 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.[^65]

The Default Service obligation under the rate cap provisions do not
continue after 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[^66].

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.

The Ohio restructuring plan closely resembles the Pennsylvania model in
that the incumbent utility retains the Default Service role under capped
rates for an extended transition period (although the transition period
is longer in Pennsylvania) and shopping credits are calculated so that
competitive providers have an incentive to offer services.

END NOTES

[^1]: . Only Georgia has implemented a natural gas competition program
    for Atlanta Gas Light that requires customers to select 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.

[^2]: . This service should be distinguished from a service that is made
    available to customers who are unable to obtain service in the
    competitive market because of their credit history or as a result of
    termination of service by a competitive supplier. Most states have
    not distinguished the type of service available to these payment
    troubled customers from that available to any customer who simply
    does not enter the competitive market, but both Texas and
    Massachusetts have made certain distinctions in their provision of
    Default Service that this report will highlight.

[^3]: . Pennsylvania Electric Shopping Statistics, January 2001,
    published quarterly by the Office of Consumer Advocate and available
    at [http://www.paoca.org]{.underline}

[^4]: . 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.

[^5]: . NEMA letter to the New York PSC, Case 96-E-0891, March 16, 2001,
    available on NEMA's website: [http://www.energy
    marketers.com]{.underline}

[^6]: . 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.

[^7]: . In the last several months, the following states have either
    delayed the adoption of retail electric competition or halted the
    consideration of proposals to adopt retail electric competition:
    North Carolina, Iowa, Minnesota, Nevada, New Mexico, Oklahoma, and
    Montana.

[^8]: . AB 1890, eff. September, 1996.

[^9]: . This listing and explanation is taken from the residential
    Southern California Edison bill which appears on its website:
    [http://www.sce.com]{.underline}

[^10]: . "CPUC 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

[^11]: . California PUC, [Final Opinion Regarding Policies Related to
    Post-Transition Ratemaking]{.underline}, Decision 00-06-034, June 8,
    2000.+

[^12]: . California PUC, [Interim Opinion Regarding Emergency Requests
    for Rate Increases]{.underline}, Decision 01-01-018, January 4,
    2001.

[^13]: . ABx1, enacted February 1, 2001.

[^14]: . [San Francisco Chronicle]{.underline}, "70% 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]{.underline}

[^15]: . Senate Bill 390 (1997), "Electric Utility Industry
    Restructuring and Customer Choice Act" (Title 69, Chapter 8, MCA).

[^16]: . [Dow Jones Newswires]{.underline}, "Montana's Industries
    Pinched by High-Flying Power Prices," January 22, 2001,
    http://interactive.wsj.com/arichive/retrieve.cgi?id=BT-CO-20010122-0011943.djml.

[^17]: ?. Electric Generation and Customer Choice Competition Act
    (1996), 66 Pa. C.S. §§101, et seq.

[^18]: . PennFuture, a Pennsylvania public interest organization, has
    monitored the development of the Pennsylvania energy markets
    closely. See http://www.pennfuture.org

[^19]: . Pennsylvania PUC, Final Order, [Guidelines Addressing Return of
    Customers to Provider of Las Resort Service]{.underline}, Docket No.
    M-00960890F0017, June 22, 2000.

[^20]: . 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.

[^21]: . Another provision of this 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.

[^22]: . **Annex A, PECO Energy rules for Competitive Default Service,
    February 28, 1999, Q.7(b).**

[^23]: . 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.

[^24]: . 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.

[^25]: . Pennsylvania PUC, Press Release, January 19, 2001.

[^26]: . 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.

[^27]: . G.L. c. 164, §1B(d) and implemented in the Massachusetts DTE
    regulations, 220 C.M.R. §11.04.

[^28]: . Massachusetts DTE, [Letter to Massachusetts Electric Company
    regarding Pricing for Default Service,]{.underline} June 1, 1999.

[^29]: . [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.

[^30]: . [Ibid,]{.underline} Order at 2.

[^31]: . 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.

[^32]: . [Order Addressing Recommendation of the Working Group on
    Default Service Issues,]{.underline} DTE 99-60-C, October 6, 2000.

[^33]: . Ibid.[, at 10.]{.underline}

[^34]: . 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}.

[^35]: ?. 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).

[^36]: . 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.

[^37]: . Chapter 301, Standard Offer Service, eff. July 31, 1999.

[^38]: . [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.

[^39]: . [Kennebec Journal]{.underline}, March 20, 2001..

[^40]: . Bill 5005, An Act Concerning Electric Restructuring, Public Act
    98-28.

[^41]: . 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.

[^42]: . 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}.

[^43]: . 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, ("New York City and
    Westchester consumers will receive lower average electric bills."),
    15 ("For all other customers, there wil be a 10% rate reduction
    phased in over the term of the Settlement."), 26 ("The 10%
    cumulative base rate reduction for commercial and residential
    customers is firm, and no longer dependent on future
    contingencies.")

[^44]: . Office of the State Comptroller, New York, "Electric
    Deregulation in New York State: The Need for a Comprehensive Plan,"
    February, 2001, Chart C.

[^45]: . PSC data as summarized by the Public Utility Law Project in
    their comments on the PSC Price Spike Mitigation Proposals, see fn.
    42.

[^46]: . [Wall Street Journal]{.underline}, "Mismanagement of NY Power
    Mkt Costs Millions--Utilities," October 5, 2000,
    [http://www.interactive.wsj.com/archive/retrieve.cgi?id+DI-CO-200001005-006703.djml]{.underline}

[^47]: . See, Department of Public Service Pricing Team, [Interim
    Pricing Report on New York State's Independent System
    Operation]{.underline}, December 2000; "Con 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; "PSC Chair Announces Five Point Plan for Regional Energy
    Markets and Managing Demand for Electricity," PSC Press Release,
    February 20, 2001.

[^48]: . 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.

[^49]: . [Energy Competition Next Steps, Draft Phase I and II Consensus
    Report]{.underline}, Case 00-M-0504, January 2001.

[^50]: . Press Release, New York State Electric and Gas Co., "NYSEG
    Proposes Electric Price Protection Plan that Freezes Rates and
    Assures Energy Reliability," March 8, 2001,
    [http://www.nyseg.com]{.underline} .

[^51]: . See, ex., Comments of the Public Utility Law Project on Price
    Spike Mitigation Proposals, Case 96-E-0897, March 13, 2001,
    [http://www.pulp.tc/html/pulp_s_comments_on_price_spike.HTM]{.underline}

[^52]: ?. "NYSEG Proposes Electric Price Protection Plan that Freezes
    Rates and Assures Energy Reliability," NYSEG Press Release, March 8,
    2001.

[^53]: . AB366 (1997), amending Chapter 703 and 704 of NRS.

[^54]: . PUCN Docket No. 97-8001 (Provider of Last Resort Service),
    Version for hearing December 30, 1998; Notice of Hearing published
    November 20, 1998.

[^55]: . Attorney General, Bureau of Consumer Protection, Comments
    Regarding Provider of Last Resort Service, Docket No. 97-8001,
    October 13, 1998, at 2.

[^56]: . SB 438, Chapter 600, Statutes of Nevada, 1999.

[^57]: . Available at: [http://www.state.nv.us.]{.underline}

[^58]: . Senate Bill 7, amending the Public Utility Regulatory Act
    (PURA), §§39.101, et seq.

[^59]: . Project 21409, Price to Beat Rulemaking.

[^60]: . Provider of Last Resort, Project 21408, Commission Rules,
    §25.43. The RFP was issued in December 2000, with final bids due by
    January 5, 2001. The Commission's schedule calls for a decision on
    the bids by March 2001.

[^61]: . Pursuant to the Commission's Consumer Protection Rules adopted
    for electric competition, a REP (including an affiliate REP) cannot
    physically disconnect a customer for nonpayment, but can only
    terminate service. Customers who do not transfer to another REP will
    automatically be provided with POLR. The POLR provider can
    disconnect service pursuant to the same consumer protections and
    procedures in effect for traditional utility service.

[^62]: . Amended Substitute Senate Bill No 3, 123^rd^ General Assembly,
    eff. October 5, 1999.

[^63]: . Sec. 4928.34 and 4928.40.

[^64]: . Rule 4901:1-10-32 and 4901:1-21-16, Ohio Administrative Code.

[^65]: . 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.

[^66]: . Sec. 4928.14.