Skip Maine state header navigation
Maine
Public Utilities Commission
2003
Annual Report on
Electric
Restructuring
Presented
to the
Utilities
and Energy Committee
December
31, 2003
TABLE OF CONTENTS
I. BACKGROUND..................................................................................................................... 4
II. RETAIL MARKET ACTIVITY............................................................................................... 4
Migration from Standard Offer – Medium and Large Customers............................. 4
Migration from Standard Offer Service – Residential and
Small Commercial................................................................................................................. 6
Emergence of a Green Market........................................................................................... 6
Northern Maine Retail Activity........................................................................................... 7
Retail Supplier Activity........................................................................................................ 8
III. STANDARD OFFER SERVICE.......................................................................................... 9
Overview of 2003.................................................................................................................. 9
Solicitations......................................................................................................................... 10
Consumer-owned Utilities (COUs)................................................................................. 12
IV. STRANDED COSTS.......................................................................................................... 12
V. OVERALL CONSUMER PRICES.................................................................................... 14
VI. GENERATION RESOURCES.......................................................................................... 15
Resource Mix...................................................................................................................... 15
Re-evaluation of Maine’s 30% RPS.............................................................................. 17
Uniform Disclosure Labels............................................................................................. 17
Voluntary Renewable R&D Fund.................................................................................. 17
VII. REGIONAL ACTIVITY....................................................................................................... 18
Notable Changes in the Past Year................................................................................ 19
VIII. AFFILIATED COMPETITIVE PROVIDERS AND COMPLIANCE COSTS.............. 22
IX. ACTIVITIES IN OTHER STATES.................................................................................... 22
Appendix A................................................................................................................................. 23
Appendix B................................................................................................................................ 30
Appendix C................................................................................................................................ 31
2003 Annual Report on Electric Restructuring
Report to the Utilities and Energy Committee
Developed Pursuant to 35-A M.R.S.A. §3217
During
its 1997 session, the Legislature enacted P.L. 1997 (the Restructuring Act),
ch. 306, codified at 35-A M.R.S.A. §3201-3217, which directed comprehensive
restructuring of Maine’s electric utility industry. Since then, the Public Utilities Commission (Commission) has
disaggregated the vertically integrated electric utilities into delivery and
generation functions, established the rates of transmission and distribution
(T&D) utilities, established rules that govern the activities of
competitive electricity providers and utilities, purchased standard offer service
through competitive bid processes, monitored retail market development, and
participated in regional wholesale market activities that affect Maine’s
electricity consumers. When compared
with the experience in other states, Maine’s retail market has developed
smoothly and effectively in most respects.
Each year, pursuant to the Restructuring Act, the
Commission submits a report to the Legislature’s Joint Standing Committee on
Utilities and Energy, describing Maine’s retail market and activities the
Commission has taken to comply with the restructuring statute. This report
describes activities during 2003.
During 2003, the retail market for Maine’s medium and
large commercial and industrial (C&I) customers continued to exhibit a
reasonable level of competitive activity, and bidding for standard offer
service was healthy. The market
continued to offer minimal competitive choice for residential and small
commercial customers, but a low standard offer price obtained in previous years
contributed to relatively low overall electricity prices. In addition, green products emerged that
show promise of sustainability.
Migration from the standard offer to a competitive market
supplier began with large business customers and extended over time to smaller
business customers. After two years,
the vast majority of large customers and a substantial number of medium
customers had migrated from the standard offer. When customers’ supply contracts expire, they may choose
between a return to standard offer service or an open market contract, based on
their expectation of future market prices and their desire for price
predictability.[2] While migration to and from the competitive
market[3]
is influenced to some extent by the relationship between standard offer and
non-standard offer prices, the prevailing trend is for customers to remain in
the open market once they have migrated from the standard offer. The graph
below shows migration among CMP and BHE medium and large customers, and
reflects an overall trend toward migration to the open 
market.
The
Commission has concluded that medium and large class standard offer prices
should track wholesale prices as closely as possible, and, accordingly, we
accepted bids for 6-month terms throughout 2003. Because of market fluctuations, in March 2003, standard offer
prices for Bangor Hydro Electric Company (BHE) and Central Maine Power Company
(CMP) customers increased significantly and in September 2003 they decreased
slightly.
By early 2002, almost
all of Maine Public Service Company’s (MPS) large customers had migrated from
standard offer service. This did not
change in 2002 and 2003.
Migration from Standard Offer Service – Residential and Small Commercial
Acquisition
and service costs for small customers are significant, and no substantial
retail market has developed. However,
because Maine’s standard offer providers are chosen through competitive bidding
based on price, all residential and small commercial customers are purchasing
generation from competitive market suppliers, and vigorous competition among
bidders for standard offer service has resulted in attractive standard offer
service rates for smaller customers.
The
northern Maine market has deviated from this pattern, with as many as 15% of
MPS’s smaller customers migrating to the competitive market. As discussed later in this report, during
2003, a competitive provider in northern Maine ceased to offer service to new
customers, and customers subsequently began returning to standard offer
service.[4] In CMP’s and BHE’s territories, fewer than
one-tenth of one percent of customers have migrated from standard offer
service. However, as discussed in the
next section, migration may increase in the future.
Emergence
of a Green Market
During
2003, “green” products began to appear through the actions of residential and
public sector aggregation groups. These activities are showing early success at
gaining customers and public recognition.
In the residential and small commercial sectors, Maine Interfaith Power
and Light (MIPL), a non-profit aggregator, began soliciting customers
interested in receiving green power during 2002. In February 2003, these customers began receiving electric supply
that was generated using 50% in-state hydroelectric and 50% in-state biomass
fuel sources. The State of Maine
provided public recognition when it contracted to purchase this product for
over 700 State government buildings. In
addition, through MIPL, customers may purchase “green tags” representing 99%
wind and 1% solar generation.[5] By November 2003, in addition to the
State purchase, 1,300 customers were purchasing the green power product and
over 100 had purchased green tags.
An
additional green product emerged for business customers in the education,
health care, and non-profit sectors, when Maine Power Options, a non-profit
aggregator representing these sectors, arranged for the provision of
electricity produced solely from in-state biomass and hydroelectric
facilities.
|
Residential and Small Commercial Customers Migrated from
Standard Offer |
||
|
|
number |
percentage |
|
CMP |
1895 |
0.4% |
|
BHE |
402 |
0.4% |
|
MPS |
2882 |
8.0% |
The table to the right shows the number and
percentage of residential and small commercial customers[6]
in CMP, BHE and MPS service territories who were receiving competitive market
electric supply in December 2003. The
numbers for CMP and BHE are up markedly from January’s counts of 113 and 148,
respectively.
Northern
Maine Retail Activity
The
northern Maine region includes the service areas of MPS and three
consumer-owned utilities: Houlton Water Company, Van Buren Light and Power
District, and Eastern Maine Electric Cooperative.[7] In contrast to the rest of Maine, which is
electrically part of the ISO-NE region, northern Maine is electrically part of
the Canadian Maritimes region. The
Maritimes region also includes the electric loads and generation of New
Brunswick, Nova Scotia, and Prince Edward Island. Load and generation in northern Maine are connected to the rest
of Maine and New England only by transmission through New Brunswick. Northern Maine load is supplied by a combination
of generating plants located in-region and in New Brunswick. The Northern Maine Independent System
Administration (NMISA) administers the bulk power and transmission systems for
the region.
Although
the retail market in the MPS service area appears fairly competitive, with
about 52% of the load currently served by non-standard offer suppliers, there have been only two suppliers active in the
northern Maine retail market since retail access began – Energy Atlantic (EA)
and WPS Energy Services, Inc. In
February 2003, Energy Atlantic announced that it would no longer accept new
customers in northern Maine, although it would continue to provide service
under existing contracts through their terms.
EA cited deficiencies in the wholesale market and the small size of the
market as the primary reasons for its withdrawal.
The
experience to date and our discussions with suppliers indicate that others
share EA’s perspective. Measures that
would make northern Maine part of a larger market (e.g., a transmission line
connecting northern Maine to the New England grid or an open market in New
Brunswick) appear to be necessary to change this situation significantly. Appendix A provides additional discussion of
these issues and describes activities the Commission has undertaken to improve
the exchange of electricity between Canada and Maine generally.
During 2003, standard offer service prices in
northern Maine continued to remain acceptable and stable, although the degree
of supplier interest in competing to provide standard offer service remained
less than in the CMP and BHE territories.
An acceptable standard offer price mitigates to some degree the concerns
resulting from the existence of only one active market participant in the
region.
Retail Supplier Activity
Twenty-three suppliers of retail electricity are
licensed to serve customers in Maine.[8] During 2003, twelve suppliers actively
served customers. Three suppliers sold
power to the residential market, while all suppliers sold power to medium and
large C&I customers to some degree.
CMP and BHE’s C&I market shows a relatively healthy dispersion of
sales among all suppliers. Well over
half of the suppliers served more than 5% of the customers or load in either
CMP or BHE’s territory.[9] MPS’s supplier activity is discussed
elsewhere in this report. We have seen
a level of consolidation among suppliers in the form of single entities owning
multiple supply subsidiaries. However,
this situation has not appeared to harm the vitality of Maine’s retail market. We will continue to monitor this and all
market conditions that affect Maine’s consumers.
III. STANDARD OFFER SERVICE
By
customer class, standard offer service supplies about 66% of the load of medium
commercial and industrial (C&I) customers and 17% of the load of large
C&I customers in Maine, as shown by the graph on the right. Standard offer service continues to supply
virtually all residential and small commercial customers, as has been the case
since retail access began. By T&D
service area, standard offer service supplies about 61% of the load of CMP
customers, 76% of the load of BHE customers and 48% of the load of MPS
customers.
The
standard offer suppliers during 2003 and corresponding prices are summarized
below. The prices shown here are
averages; actual prices for the medium class may vary by month and for the
large class by month and time of day.
For more detailed prices, please see the Commission’s web page at http://www.state.me.us/mpuc/new%20standard%20offer/standard_offer_rates.htm.
Average
Standard Offer Prices in 2003
The
Commission held several solicitations for standard offer service during
2003. These solicitations were
competitive and successful, resulting in retail standard offer suppliers and
market-based prices for all customer classes.
Suppliers continue to become more comfortable with Maine’s retail
standard offer service model, and the level of participation in our
solicitations reflects this comfort.
The
first solicitation of the year was for standard offer service for the CMP and
BHE medium and large classes for the term beginning March 2003. The Commission issued RFPs in November 2002
and, in response, suppliers submitted indicative bid prices in December
2002. Staff and suppliers negotiated
and resolved contract terms and, in January 2003, suppliers submitted final
binding bids. After evaluating the
final proposals, the Commission designated FPL Energy Power Marketing, Inc.
(FPL) as the standard offer provider for the CMP and BHE medium classes and
Select Energy, Inc. (Select) as the standard offer provider for the CMP and BHE
large classes for the term March 1 through August 31, 2003. The Commission chose 6-month term bids for
all four classes so that standard offer prices could more closely follow
changes in market prices than would be possible, for instance, in the case of a
1-year term.[10]
The
average prices for standard offer service during the March-August period based
on the final bids are shown below:
|
CMP BHE Medium
C&I 5.9 ¢/kWh 5.9 ¢/kWh Large C&I 6.1 ¢/kWh 5.8
¢/kWh |
The
second standard offer solicitation of the year was again for the CMP and BHE
medium and large classes, for the term beginning September 2003. The Commission issued an RFP in early June
2003 and, after receiving indicative bids, negotiating contract and other
non-price terms, and receiving final bids, again designated FPL and Select to
serve the medium and large classes, respectively. The term was again set at six months (September-February) and the
average prices were set as shown below:
|
CMP BHE Medium
C&I 5.6
¢/kWh 5.6 ¢/kWh Large
C&I 5.7 ¢/kWh 5.4 ¢/kWh |
The
third solicitation of 2003 was to acquire standard offer service for MPS
customers. This solicitation covered
all three standard offer classes for the term beginning March 2004. The Commission sought proposals for term
lengths of 1 year and 34 months, the latter term to coincide with the end of
MPS’s purchased power contract with Wheelabrator-Sherman (W-S). MPS solicited bids to purchase its W-S
entitlement in a concurrent RFP process, and standard offer-entitlement
cross-contingent bids were explicitly allowed.
The
MPS standard offer RFP was issued in September. Suppliers submitted indicative bids in mid-October, and staff and
suppliers then negotiated and resolved contract and other non-price terms. Based on the final binding bids that
suppliers submitted on November 3, the Commission designated WPS as the
standard offer provider for all three MPS standard offer classes for a 34-month
term, March 1, 2004 – December 31, 2006.
The resulting standard offer prices are shown below:
MPS
Standard Offer – Term Beginning March 1, 2004
|
Class Price
Residential/Small Commercial 5.459 ¢/kWh Medium C&I 5.810 ¢/kWh Large C&I 6.400 ¢/kWh |
WPS’s
standard offer bid was contingent on also receiving the Wheelabrator-Sherman
entitlement at its bid price of, on average, 3.475¢/kWh for the same 34-month
term.
The
fourth and final standard offer solicitation of 2003 began with the release of
RFPs on November 18. This solicitation,
which is still ongoing, is to acquire standard offer service for the CMP and
BHE medium and large classes for the term beginning March 2004.
A
3-year standard offer arrangement with Constellation Power Source Maine, LLC
(Constellation) that began in March of 2002 continued to supply CMP and BHE
residential and small commercial customers during 2003. The standard offer prices, 4.95 cents/kWh
for CMP and 5.0 cents/kWh for BHE, will remain in effect through February
2005.
COUs carry out bid processes to procure standard
offer service in their territories. The
following table displays their current standard offer prices:
Standard
Offer Prices - Consumer-Owned Utilities
|
Utility |
Price |
Supplier |
|
Eastern Maine Electric Cooperative |
6.75
c/kWh |
WPS |
|
Houlton Water Company |
5.387¢/kWh |
WPS |
|
Van Buren Light and Power |
5.76
¢/kWh |
WPS |
|
Fox Islands Electric Cooperative * |
4.05
¢/kWh |
Exelon Power |
|
Madison Electric Works * |
6.604
¢/kWh |
Select |
|
Swans Island Electric Cooperative * |
3.5
¢/kWh–5.7¢/kWh |
Select |
|
Kennebunk Light and Power Co. * |
3.88
¢/kWh |
Exelon Power |
|
Monhegan Electric |
Exempt |
|
|
Matinicus Plantation Electric Co. |
Exempt |
|
|
Isle au Haut |
Exempt |
|
* Rate is approximate. It may vary monthly and is subject to a monthly true-up adjustment to reflect the actual costs of supply.
The Restructuring Act allows CMP, BHE and MPS to recover stranded costs in the rates they charge for delivery service. Stranded costs reflect the net, above-market costs for generation obligations that utilities incurred prior to industry restructuring. For example, stranded costs include the difference between payments the utilities must make pursuant to pre-existing purchased power contracts (primarily with qualifying facilities (QFs)) and the current market value of that power.
Stranded cost rates are re-set for CMP, BHE and MPS approximately every two to three years. The adjustments coincide with the sale terms of the utilities’ QF entitlements, because the amounts received from the entitlements sales offset stranded costs and are a significant component of total stranded cost rates. CMP and BHE stranded costs were re-set in 2002, while MPS’s rates are being considered now for the period beginning March 1, 2004.
The most significant changes in stranded costs will occur when utilities’ QF contracts expire. BHE’s stranded costs will decline significantly in 2006, while CMP’s will decline during the second half of the decade. Projections of stranded costs are shown in the chart below.
The major components of each utility’s stranded costs over the year March 2003 – February 2004 are set forth below:
Until 2003, stranded costs also included, as an offset, the proceeds from the utilities’ generation asset sales (referred to as the Asset Sale Gain Account or ASGA). In 2002, the ASGA offset CMP’s and BHE’s stranded costs by $43M and $5M respectively. However, in spring of 2001, the Commission approved a 0.8¢/kWh reduction in the stranded cost component of delivery rates for CMP’s medium and large customers to mitigate the impact of significantly increased market generation prices. In 2002, the Commission approved a modest extension of the rate mitigation for CMP’s and BHE’s large industrial customers (0.45¢/kWH and 0.4¢/kWh respectively), and in February 2003, the Commission approved a 0.3¢/kWh mitigation for CMP’s medium and large customers through February 2005. These rate mitigation activities exhausted CMP’s and BHE’s Asset Sale Gain Accounts.
Many consumers in Maine pay a lower overall price for
their electricity now than they did before restructuring. This is especially notable in CMP’s
territory, where distribution and stranded cost rates have decreased steadily
since CMP sold its generating assets in 1999.[11] Rate changes since 1999 are attributable to
many factors other than restructuring, including such diverse factors as
natural gas prices, utility cost containment efforts, and FERC cost-allocation
decisions. Furthermore, the prices for
C&I customers in particular vary considerably based on their operating
characteristics and their supply contract terms. Nonetheless, a comparison of average electricity prices in 1999
and 2003 is shown in the tables below.
Average Residential Rates Average Large
Industrial Rates
For
Customers on Standard Offer[12]
T&D
rate changes may occur in one of three T&D rate components. Distribution rates may change to reflect the
utility’s costs of delivering power and maintaining customer service. Transmission rates are determined annually
by the Federal Energy Regulatory Commission (FERC), and reflect the cost of
maintaining transmission facilities used to transport power throughout the region. Finally, stranded cost rate components
change as utilities’ generation contracts expire and market conditions
change. In addition, generation supply
prices – both standard offer and open market – fluctuate over time and may vary
considerably from supplier to supplier.
The following charts display the current components of
residential and large industrial prices in BHE, CMP, and MPS territories. The charts show that stranded costs still
comprise a significant portion of customers’ rates, while transmission rates
have a negligible impact on total rates.
Resource Mix
The Restructuring Act establishes a “30% Resource
Portfolio Standard (RPS),” that requires electricity suppliers (including
standard offer suppliers) to supply 30% of their Maine load from “eligible
resources.” The Act defines eligible resources to be generating units whose
capacity does not exceed 100 megawatts and that produce electricity from tidal,
fuel cells, solar, wind, geothermal, hydroelectric, biomass, and municipal
solid waste in conjunction with recycling, that qualify as small power
producers under Federal regulations, or that are efficient cogeneration
units.
During 2002,[13]
approximately 38% of Maine’s load was supplied by eligible resources. Approximately 30% was supplied by resources
designated as renewable in the Restructuring Act (hydroelectric, biomass,
municipal solid waste, wind, and solar).
Overall, suppliers used system power, which is power purchased from the
New England or Maritimes control area through daily bids, to supply over 45% of
Maine’s load requirements. A portion of
the system power was used to comply with Maine’s 30% requirement, while the
majority (over 80%) of the RPS was met through dedicated contracts. The following chart displays the resources
serving customers in 2002. Appendix B
contains additional information.
During 2002, NEPOOL implemented a “tradable attribute” certificate system known as the Generation Information System (GIS). The GIS allows for the trading of electricity attributes (e.g., fuel source and emissions levels) separate from the energy commodity. During 2003, the Commission revised i