Skip Maine state header navigation
MAINE PUBLIC UTILITIES COMMISSION
REPORT on UTILITY INCENTIVES MECHANISMS
for the
PROMOTION
OF ENERGY EFFICIENCY
and SYSTEM
RELIABILITY
Presented
to the
February
1, 2004
TABLE OF CONTENTS
During its
2003 session, the Legislature passed An Act To Encourage Energy Efficiency and
Security. The Act directs the Public
Utilities Commission to investigate regulatory mechanisms and rate designs that
provide incentives for transmission and distribution utilities to promote
energy efficiency and the security and robustness of the electric grid. The Act
requires that the Commission submit a report to the Joint Standing Committee on
Utilities and Energy by February 1, 2004.
In broad outline, the Commission has concluded that the
incentives utilities currently have under rate cap regulation to increase
sales, although magnified to some degree, are similar in kind to the incentives
they had under more traditional regulation.
Moreover, it does not appear that utilities currently acting on these
incentives have a significant opportunity to blunt the effectiveness of current
efficiency and conservation programs in Maine, especially now that those
programs have been removed from utility control. Finally, while there are a number of tools available to the
Legislature and the Commission that could to some degree lessen the remaining
utility incentives to frustrate conservation efforts, these tools are likely to
have ancillary consequences that could, in the Commission's view, create
substantial adverse effects. For these
reasons, the Commission does not recommend that any major revisions to Maine's
current regulatory policies concerning utility incentives and conservation be
undertaken.
In addition, the Commission believes that the current
system of ensuring adequate service reliability through objective service
quality metrics, backed by meaningful penalties, incorporated as part of a
utility’s alternative rate plan, along with the Commission’s ability to use its
traditional tools to ensure adequate service, is working well. Accordingly, the Commission recommends that
no legislative changes be made in this area.
The Commission will continue to monitor Maine’s transmission and
distribution utilities’ service quality performance and refine the standards
and penalty mechanisms in ways that improve their operation.
The report is structured into sections that contain
discussions and analyses in the following areas:
The report describes how regulatory structures changed after the restructuring of Maine’s electric industry in 2000. Prior to industry restructuring, the Maine Commission regulated all aspects of retail transactions between Maine utilities and its ratepayers. After industry restructuring, the generation portion of electricity service was no longer subject to rate regulation and the regulated portion of electricity service was broken up into four pieces: (1) the generation component; (2) the transmission component; (3) the stranded cost component; and (4) the distribution delivery component. The report discusses the regulatory structures that now govern these four distinct components. In addition, the impacts of industry restructuring on utility rate design and the obligation of utilities to conduct conservation programs are reviewed.
III. Analysis of Current Regulatory Mechanisms
Electricity
rates currently paid by consumers in Maine are a composite of competitive and
regulated services, and reflect a variety of ratemaking methodologies that
include both traditional and alternative regulation. The report provides an analysis and discussion of the impact of
this regulatory mix on rate levels and operational efficiencies, system
reliability (both on a regional and distribution system level), energy
efficiency, utility rate structures, and economic development incentives.
The report
presents and discusses regulatory mechanisms that can be used to alter utility
financial incentives with respect to energy efficiency and system
reliability. These are revenue decoupling, lost revenue
adjustments, return on equity
adjustments, shared savings mechanisms, service quality standards, direct pass-through of costs, and a
fixed charge rate design. The report
includes tables that illustrate the bill impacts for residential and small commercial
customers of moving to a completely fixed charge rate design. A table at the end of the section summarizes
the incentive impacts of various regulatory mechanisms.
V. OTHER
STATE MECHANISMS
The Commission conducted a survey of other states and
a literature search to determine the existence of possible mechanisms that can
be used to affect or alter utility financial incentives with respect to energy
efficiency and conservation and system reliability. The results of the research are presented in the report and
summarized in tables.
The report presents Commission recommendations
regarding utility incentive mechanisms with respect to system reliability and
energy efficiency, and viable alternatives that can address legislatively
specified policies and goals.
The issues involving system reliability are relatively
straightforward. The Commission’s view
is that, as a general matter, the current regulatory framework has produced a
reasonable balance between system reliability and ratepayer cost. Accordingly, no major changes to the
regulatory scheme are recommended to address reliability incentives.
The
issues involving energy efficiency and the promotion of electricity consumption
are relatively more complex. The
Legislature must consider in the first instance whether the current incentives
that utilities have to promote the use of electricity raise substantial public
interest concerns. The threshold
question in this context is whether it is the policy of this State to
discourage the consumption of electricity.
If this is the policy of the State, the next consideration is whether
utilities are particularly effective in promoting the use of electricity and
thereby frustrating the State’s ability to attain its policy goal. Finally, if both questions are answered in
the affirmative, in the Commission’s view the Legislature should consider
whether potential changes to the regulatory structure to alter utility
incentives might nevertheless create greater problems than they solve.
The
Commission expresses no opinion on whether the State should adopt a policy that
the consumption of electricity is against the public interest. However, the Commission has serious concerns
regarding the potential consequences of efforts to remove the financial
incentives of utilities to promote their product through fundamental changes in
regulatory structure or rate design.
A
primary question is whether the current regulatory framework is subverting
efforts to promote conservation and the efficient use of electricity. The Commission’s view is that the current
framework does not have this effect.
The Commission has some limited evidence that utility efforts to promote
consumption are not particularly effective.
More importantly, however, the Commission’s view is that conservation
and energy efficiency are driven more by customer decisions than by utility
action. Accordingly, it is more
important that consumers have proper price signals to conserve and that the
State retain a vibrant state-wide conservation program (i.e., the Commission’s
Efficiency Maine program) than it is to change utilities’ actions.
It
is for these reasons that the Commission recommends no fundamental change in
the current regulatory structure to address utility financial incentives
regarding the consumption of electricity.
Nevertheless, the report outlines and evaluates several alternative
approaches if the Legislature decides that public policy requires that current
financial incentives should be altered.
Recommended Regulatory Approach
The
Commission recommends that no fundamental changes be made to the current
regulatory structure to alter utility financial incentives.
Rate Cap Regulation
The Commission recommends that multi-year rate cap
plans remain the basic regulatory approach for Maine’s T&D utilities’
distribution delivery rates.
System
Reliability Mechanisms
The Commission recommends that service quality
standards continue as the primary means to ensure adequate system reliability
and that efforts continue to be made to improve the operation of the standards.
Energy Efficiency Mechanisms
The Commission does not recommend that regulatory mechanisms be adopted to alter utilities’ current incentives with respect to electricity consumption and energy efficiency.
Rate Design
The Commission recommends against the adoption of
a fixed charge rate design for the primary purpose of removing utility
incentives to promote electricity consumption.
Alternative
Approaches
If the Legislature determines that mechanisms should be employed to change utility incentives with respect to energy efficiency or system reliability, the report discusses approaches that should be considered.
Fixed Charge Rate Design
In the
event the Legislature decides that some regulatory change should occur to
eliminate utility financial incentives to promote electricity consumption, the
Commission recommends that a legislative mandate be adopted that directs the
Commission to move towards a fixed charge rate design. Because movement to a fixed charge rate
design would involve substantial bill impacts for many customers (e.g., an
increase from $7.18 to $35.13 for CMP’s smallest residential customers), the
Legislature should consider mandating that rate design changes occur gradually
over time.
Revenue Reconciliation Stranded Cost Rate-Setting
In the event that the Legislature
desires to take steps to address incentives regarding the promotion of
electricity consumption, it should consider amending 35-A M.R.S.A. § 3208
to clearly authorize the Commission to adopt revenue and cost reconciliation
mechanisms in setting stranded cost rates.
If such a mechanism were adopted, a utility’s incentive to increase
sales would be reduced, although not eliminated, because a substantial amount
of utility costs would continue to be recovered through usage sensitive
charges.
Return on Equity Adjustment Mechanism
A mechanism whereby a utility’s return on equity is adjusted, either up or down, based on its performance in specified areas can be an effective means to impact incentives. The mechanism is subjective by its nature and the Commission would make determinations based primarily on its expert judgment. The approach is inconsistent with current rate plans and implementation is likely to be extremely contentious. However, a return on equity adjustment mechanism could be made part of a multi-year rate plan with rate adjustments occurring as part of the annual ARP reviews.
Multi-Year Revenue Cap
If the Legislature determines that the State’s basic regulatory structure should be changed from the current rate cap regulation to alter incentives so utilities are financially neutral to electricity sale levels, a multi-year revenue cap program for establishing distribution rates can be considered. This type of revenue cap mechanism, if it can be designed correctly, would continue to provide utilities with the incentive to seek operational efficiencies and to reduce their cost of service. However, the Commission has substantial concern over unintended consequences that may accompany the adoption of a regulatory structure that is so dependent on unpredictable events.
Prohibition or Regulation of Promotional
Activities
If the Legislature determines that utility promotion of electricity consumption is a serious public interest problem, the most direct solution would be a legislative ban or regulation of promotional activities. Such an approach would raise First Amendment issues that the Commission has not analyzed. The most direct approach would be a ban on promotional advertising. A less intrusive approach would be for all such advertising to include some type of required statement, such as information on the environmental impacts of electricity consumption.
During its
2003 session, the Legislature passed An Act To Encourage Energy Efficiency and
Security.[1] The Act directs the Public Utilities
Commission (“Commission”) to investigate regulatory mechanisms and rate designs
that provide incentives for transmission and distribution (“T&D”) utilities
to promote energy efficiency and the security and robustness[2]
of the electric grid. The Act requires that the Commission submit a report to
the Joint Standing Committee on Utilities and Energy by February 1, 2004.
As a vehicle for conducting its investigation, the
Commission initiated an Inquiry on June 18, 2003.[3] As part of the Inquiry, the Commission
solicited written comment from interested persons on all issues relevant to the
investigation, met or had discussions with entities having expertise in the
area of utility incentives, and conducted a survey and other research into
mechanisms used in other states to promote energy efficiency and grid
reliability. Subsequently, the Commission
released a draft report, sought written comment on the draft report from all
interested entities, and held a public meeting on all issues relevant to the
investigation.[4]
In broad outline, the Commission has concluded that the
incentives utilities currently have under rate cap regulation to increase
sales, although magnified to some degree, are similar in kind to the incentives
they had under more traditional regulation.
Moreover, it does not appear that utilities currently acting on these
incentives have a significant opportunity to blunt the effectiveness of current
efficiency and conservation programs in Maine, especially now that those
programs have been removed from utility control. Finally, while there are a number of tools available to the
Legislature and the Commission that could to some degree lessen the remaining
utility incentives to frustrate conservation efforts, these tools are likely to
have ancillary consequences that could, in the Commission's view, create
substantial adverse effects. For these
reasons, the Commission does not recommend that any major revisions to Maine's
current regulatory policies concerning utility incentives and conservation be
undertaken.
In addition, the Commission believes that the current
system of ensuring adequate service reliability through objective service
quality metrics, backed by meaningful penalties, incorporated as part of a
utility’s alternative rate plan, along with the Commission’s ability to use its
traditional tools to ensure adequate service, is working well. Accordingly, the Commission recommends that
no legislative changes be made in this area.
The Commission will continue to monitor Maine’s transmission and
distribution utilities’ service quality performance and refine the standards and
penalty mechanisms in ways that improve their operation.
This report is structured as follows:
A. Background
1. Traditional
Regulation
Rates and Rate
Design
Pursuant to the provisions of section 301 of Title 35-A, the rates set by the Public Utilities Commission must be just and reasonable. This means that the rates must be fair to the consumer and at the same time must provide the utility with the opportunity to recover its operating expenses and to earn a fair return on its investment. For nearly a century, the Commission attempted to accomplish these objectives through establishing rates based on a rate-of-return or cost-plus rate-setting methodology that is typically referred to as traditional regulation.
Under traditional
regulation, utility rates are set through periodic litigated rate cases. In these cases, the Commission examines a
utility’s underlying costs, current and expected revenues, and reasonable rate
of return on capital investment. The
Commission prospectively establishes rates to allow utilities a reasonable
opportunity to recover their prudent costs[5]
of providing safe and adequate service, as well as a reasonable return on
shareholder investment. Rate cases are
adjudicatory in nature, and can be initiated by the utility, by the Commission,
or through petition of a utility’s ratepayers.
A contested rate case is an extremely complex and imprecise undertaking
in the context of multi-million dollar utility companies. Such cases generally take a year to process
and resolve, and require a substantial devotion of the resources of the
Commission, the utility, the Public Advocate, and interested intervenors.
As part of the rate-setting process,
the Commission must also design rates which allow the utility an opportunity to
recover its revenue requirement (operating expenses plus a return of and on
investment). Revenue requirements can
be recovered through three different types of charges or rates: customer or
fixed charges;[6] usage or
energy (kWh) charges; and demand (kW) charges.
Pursuant to the enactment of the Electric Rate Reform Act in the mid-1980s,[7] the Commission endeavored to design electric rates in a manner that more closely reflected the underlying costs of service. This involved establishing rates based on the marginal cost of service, designing rates to reflect cost differences between seasons and time-of-day, and adopting inverted block rates (in which rates increase with higher usage amounts) for residential customers. This approach to ratemaking was intended to promote economic efficiency and the proper allocation of societal resources.
Operational
Efficiency
Because
utility rates are reset periodically based on an examination of the utility’s
ongoing costs, traditional regulation does not provide strong incentives for
utilities to conduct their business in the most efficient manner or to provide
their service at the lowest possible cost.
As a practical matter, the Commission’s traditional review cannot
uncover all potential inefficiencies, and the regulatory approach does not
provide incentives for efficient business operations to nearly the same degree
as a competitive market. Unlike a
competitive business that must price its product based on what the market will
bear, a utility whose costs are rising, or whose shareholder returns are
considered insufficient, can file for a rate increase. Conversely, a utility that is able to reduce
its costs through efficiency measures faces the possibility that ratepayers or
the Commission will initiate a rate case to lower rates on the grounds that the
utility’s returns are too high. Thus,
the traditional regulatory system does not instill the type of business
discipline that occurs in competitive markets.
Reliability Incentives
Under
traditional regulation, utilities were guaranteed the opportunity to obtain a
fair return on their total capital investment (referred to as ratebase). In addition, under certain circumstances, a
utility might be able to enhance its earnings per share by making additional
investments in its plant.[8] Given the utilities’ near guarantee of
recovery of investment in their systems, the incentive for utilities was to
“gold-plate” their systems to some degree to reduce any potential reliability
problems that might lead to negative public reactions and greater Commission
scrutiny. Traditional regulation has
limited effectiveness in protecting against “overbuilding” and its resulting
unnecessary increases in rates.
To
the extent that reliability problems existed despite the general incentive in
favor of capital expenditures,[9]
the primary remedy under traditional regulation was for the Commission to react
to individual customer complaints. In
addition, as part of a rate case proceeding, the Commission would ordinarily
hold public witness hearings where customers of the utility could testify about
any service problems. This testimony
was often anecdotal and did not provide an objective basis to determine whether
the utility was in fact providing adequate and reliable service on a
system-wide basis. If the Commission
found that the utility was violating its general obligation to provide
reasonably reliable and adequate service, the primary tool for addressing the
matter was to penalize the utility through a reduction in the utility’s return
on equity. While any attempt to reduce
a utility’s return on equity due to service quality issues would likely be
contested and subject to court review, the potential for the Commission to act
in this manner provided some incentive for utilities to maintain adequate service.
Efficiency Incentives
Under
traditional regulation, utilities have the financial incentive to
promote the consumption of electricity, and little incentive to pursue energy
efficiency or conservation.[10] This is because total company revenues (and
thus profits) are a function of sales volumes.
Thus, every kilowatt-hour sold increases profits, while every
kilowatt-hour saved lowers profits. [11] The disincentive with respect to energy
efficiency and conservation is diminished to some degree by the ability of
utilities to make up for lost revenues through periodic rate cases. However, rate cases are costly and take a
substantial amount of time during which the impact of lost revenues continues,
and the ultimate result is higher utility rates that could lead to reduced
business and public bad will. The
financial incentive between rate cases is for a utility to act to increase
electricity sales.
Prior to the restructuring of the electric industry, utilities were obligated to pursue energy efficiency and conservation measures, if such measures were less costly than the generation supply alternative. Because of the inherent disincentive against reduced consumption, the Commission was required to carefully monitor utility operations to ensure that utilities acted in a manner consistent with their legal obligations.
2. Development of Alternative Regulation
In late 1993, following a series of rate increases resulting from a number of causes, including declining sales brought on by a downturn in the economy, introduction of a new rate design, and increases in utility costs above the rate of inflation, the Commission concluded that it should consider setting Central Maine Power Company’s (“CMP”) rates by means of a rate cap approach. Under a rate cap approach, CMP’s rates would be reset based on an external index over a multi-year period. The Commission concluded that a multi-year price-cap, also referred to as an incentive rate plan or Alternative Rate Plan (“ARP”), could provide the following benefits to Maine ratepayers: (1) electricity prices would continue to be regulated in a comprehensible and predictable way; (2) rate predictability and stability were more likely; (3) regulatory “administration” costs could be reduced, thereby allowing for the conduct of other important regulatory activities and for CMP to expend more time and resources in managing its operations; (4) risks could be shifted to shareholders and away from ratepayers (in a way that is manageable from the utility’s financial perspective); and (5) because exceptional cost management could lead to enhanced profitability for shareholders, stronger incentives for cost minimization would be created.[12] Because the ability of a utility to file for a rate increase is greatly restricted under an ARP, the Commission noted that there is an enhanced incentive, relative to traditional regulation, for a utility to cut costs in ways that could damage system reliability and to increase consumption by cutting back efficiency programs.
The Commission approved an alternative rate plan for CMP in 1995 that was among the first price-cap plans for any electric utility in the country.[13] CMP’s first five-year price‑cap plan, also now referred to as ARP I, reset CMP’s rates annually based on an external index calculated by inflation minus a productivity offset, plus or minus earnings outside a deadband and/or certain costs which qualified as mandated costs. To address incentives that might have been created for the utility to cut costs at the expense of system reliability, the plan also included substantial financial penalties for failure to attain the standards set forth in the ARP’s Service Quality Index (“SQI”). ARP I’s SQI measured CMP’s performance in five areas of which two addressed reliability and three concerned customer service.
The reliability indices included the System Average Interruption Frequency Index (“SAIFI”), which measures the average frequency of sustained interruptions per customer over the year, and the Customer Average Interruption Duration Index (“CAIDI”), which is a calculation of the average time required to restore service to the average customer per sustained interruption. ARP I’s SQI provided for penalties of up to $3 million if CMP failed to meet the SQI standards in any one year. In approving ARP I, the Commission concluded that the specific service quality standards of the SQI, with automatic penalties assessed if service deteriorated beyond baseline levels, was superior to the traditional tools of penalizing the Company for poor service through litigated proceedings.
In addition, to address the
enhanced disincentive regarding energy efficiency and conservation, ARP I
required CMP to submit annual energy resource plans, which included
kilowatt-hour and kilowatt savings associated with demand side management
(“DSM”) activities. In the event CMP
failed to achieve 90% of targeted DSM savings in any one year, it would be
subject to a penalty of between $1.5 million to $5 million. This mechanism was effective in ensuring that
CMP’s conservation activities produced energy savings at the targeted
levels. However, the motivational
impacts of the targets ceased as soon as the targets were met.
B. Regulatory
Structures After Industry Restructuring
For the entire 20th century,
Maine’s utilities were vertically integrated and were monopolies with respect
to all aspects of providing and delivering the electricity “product.” Because of their monopoly status, the Maine
Commission regulated all aspects of retail transactions between Maine utilities
and its ratepayers.
On March 1, 2000, Maine’s electric industry was
restructured to provide Maine consumers with the opportunity to purchase
generation services from a competitive market and as of that date, the
generation portion of electricity service was no longer subject to rate
regulation in Maine. As a result of
restructuring, the bundled electricity “product” has been broken up into four
pieces: (1) the generation component; (2) the transmission component; (3) the
stranded cost component; and (4) the distribution delivery component.
In this portion of the report, the Commission discusses the regulatory structures that now govern these four distinct components. In addition, the impacts of industry restructuring on utility rate design and the obligation to conduct conservation programs are reviewed.
1. Generation Component
As part
of industry restructuring, investor-owned electric utilities[14] in Maine were required to divest their
generation assets on or before March 1, 2000, and to the extent that a utility
desires to enter the competitive retail generation supply market, such activity
has to occur through a separate corporate affiliate. Upon restructuring, utilities no longer have the obligation to
ensure an adequate supply of generation, and construction of new generation as
well as the continued operation of existing generation is now subject to market
forces. Like other competitive
businesses, generators and competitive electricity suppliers have a direct financial interest in promoting the sale of
their products.
2. FERC Regulation of Transmission Rates
The unbundling of generation costs from utility rates
has resulted in the Federal Energy Regulatory Commission (“FERC”) asserting
jurisdiction over retail transmission rates.
Under FERC regulation, transmission rates are set through a formula in
which rates are established annually based on the utility’s prior year’s costs
and revenues. This type of regulation
provides little incentive for operational efficiency because rates are based
directly on utility costs. Because
rates are reset annually, the FERC ratemaking methodology provides even less
incentive for operational efficiency than traditional regulation in that a
utility’s actual costs are, in essence, automatically recovered. The primary means to ensure some reasonable
level of efficiency and to prevent the recovery of imprudent or otherwise
impermissible costs from ratepayers is through Commission intervention as a party
in the FERC’s annual implementation of the transmission rate formulas. The Commission routinely intervenes in Maine
utilities’ annual formula filings in an effort to ensure that transmission
rates are just and reasonable.
FERC’s ratemaking approach should
generally have the effect of reducing utility reluctance to invest in
reliability improvements in that timely cost recovery is essentially
ensured. However, utilities have
recently argued before FERC (in the context of a proposal to form a Regional
Transmission Organization) that the existing regulatory system, given the risks
associated with the construction of transmission facilities, does not provide
sufficient incentives for the utilities to invest in their transmission
systems. The utilities are asking FERC
for significantly enhanced allowed returns as an inducement to construct
transmission facilities.[15]
Because FERC’s ratemaking
methodology annually updates rates based on the previous year’s revenues, the
utility’s incentive to increase sales and disincentive to promote energy
efficiency and conservation is reduced to some degree relative to traditional
or rate cap regulation. The overall
impact of FERC regulation on utilities’ motivation regarding sales is not
substantial because for most customers transmission is not a substantial part
of the total utility rate.[16]
3. Stranded
Cost Rate Setting
Under the provisions of
the Restructuring Act, the Commission was directed to determine and permit
recovery of each utility’s stranded costs which are defined as the legitimate, verifiable
and unmitigatible costs made unrecoverable as a result of the restructuring of
the electric industry.[17] Prior to the onset of retail access, and
periodically since that time, the Commission has set stranded cost rates for
each of the State’s investor-owned utilities.
The difference between the ongoing costs of qualifying facility (“QF”)
contracts and the value of the output of those contracts in the wholesale
competitive market, generation-related regulatory assets, and costs related to
Maine Yankee are the primary components of stranded costs in Maine.
Because a major
component of each of the utility’s stranded costs is dependent on the results
of the sales of the output from the utility’s QF contracts, the Commission has
concluded that it is not feasible to employ an alternative rate setting
mechanism for stranded costs.
Therefore, the Commission has continued to rely on traditional cost of
service rate setting for this category of costs. The Commission has set stranded costs for multi-year periods
which run concurrently with the utility’s sale of its QF entitlements.
4. Distribution
Delivery Rates
During 2000, the Commission
approved a second alternative rate plan for CMP (referred to as ARP 2000)
applicable in the newly restructured environment.[18] Because generation service is now subject to
market competition , and because FERC has asserted jurisdiction over
transmission service following a state’s unbundling of generation from delivery
service, ARP 2000 only applies to distribution delivery rates and service. Similar to ARP I, ARP 2000 adjusts rates
annually by a formula of inflation minus a productivity offset adjusted for
mandated costs, earnings sharing, and service quality penalties. ARP 2000’s SQI mechanism contains the same two
indices, CAIDI and SAIFI, to measure reliability. Although CMP’s revenues have decreased by about one-third as a
result of restructuring, the ARP 2000 plan increased the maximum penalty level
for failing to meet the SQI standards from $3.0 million to $3.6 million.
During 2002, the Commission
approved an ARP for BHE. [19] Similar to CMP’s ARP 2000, the BHE ARP
applies only to distribution rates, contains CAIDI and SAIFI performance
metrics, and requires BHE to file an Annual Reliability Improvement Report.
At the present time, the
only investor-owned utility whose distribution rates remain subject to
traditional regulation is MPS. During
2003, MPS submitted a proposal to the Commission requesting a $1.267 million
increase in distribution revenues as a “starting point” adjustment for its
proposed seven-year ARP. The Commission
approved a stipulation which resolved the Company’s “starting point” revenue
requirement request but did not address MPS’s proposed ARP. [20] Under the terms of the stipulation, MPS was
given until the end of 2003 to determine whether it wanted to pursue its ARP
proposal. MPS has informed the
Commission that it does not wish to pursue its proposal at this time.
5. T&D
Rate Design
Upon
the restructuring of the industry, the Commission removed generation-related
costs from utility rates in a manner that avoided negative overall rate impacts
for customers and customer classes. The
result is that current T&D rates continue to have a basic design that
existed when utilities provided generation service. Under that design, T&D utility revenues are primarily
recovered through usage sensitive energy charges for the utilities’ residential
and small commercial customers, and through usage sensitive energy and demand
charges for the utilities’ large commercial and industrial customers. Currently, a very small percentage of
utilities’ revenues are recovered through fixed or customer charges that do not
vary with usage.
6. Conservation Obligations
Prior to industry restructuring, utilities had the obligation to provide generation
supply through a least cost mix of resources that included conservation or DSM
programs. In particular, utilities were
required to pursue DSM if less costly than an equivalent amount of supply. Thus, utilities were required to conduct DSM
even though it was against their financial interest to reduce electricity
consumption.[21]
The obligation of Maine utilities
to provide generation services through a least cost mix of resources ended with
the restructuring of the industry.
Utilities are now solely “wires” companies. As such, the pursuit of conservation and DSM are no longer an
integral part of the service provided by Maine utilities. In recognition of this change and the
continued financial incentive that utilities have not to reduce electricity
consumption, the Legislature, pursuant to the recently enacted Conservation
Act, transferred responsibilities to implement and administer energy efficiency
programs to the Commission.[22]
III. Analysis of Current Regulatory Mechanisms
Electricity
rates currently paid by consumers in Maine are a composite of competitive and
regulated services, and reflect a variety of ratemaking methodologies. This section of the report provides an
analysis and discussion of the impact of this regulatory mix on rate levels and
operational efficiencies, energy efficiency and reliability incentives, T&D
rate structures, and economic development incentives.
A. Rate Levels and Operational
Efficiencies
In
1992, the Commission was faced with what amounted to a ratepayer revolt.[23] Numerous ratepayers expressed concern with
both the high level and unpredictability of CMP’s rates. On an overall basis, the Commission views
the alternative rate plans adopted in Maine to date to have effectively
addressed these concerns. Rate stability and predictability have been enhanced
by the ARP’s use of a pre-established formula to set rates over a period of
years. The ARP mechanism has reduced
electric rate volatility by limiting rate changes to once a year and has
allowed customers to anticipate and take into account future levels of
electricity rates.[24]
Not
only have the ARPs provided utility ratepayers with a greater rate stability
and rate predictability, but they have also had a positive impact on overall
rate levels. The annual productivity
offsets in CMP’s ARP 2000 range from a low of 2.0% in 2002 up to 2.9% in
2007. During the course of ARP 2000,
these productivity offsets will serve to decrease distribution rates in real
dollar terms by 18.0%. Under the BHE
ARP, BHE’s distribution rates decreased by 2.5% last year, and are projected to
decrease by approximately 2.75% next year, and given current inflation
forecasts, by 2.75% in 2005 and by 2.8% in both 2006 and 2007.
By
severing the ratemaking link between a utility’s rates and its costs over a
multi-year period and restricting the ability of utilities to file for rate
increases whenever their costs increase or revenues diminish, the rate cap
plans have provided a powerful incentive for the utilities to reduce costs and
increase operational efficiency.
Moreover, the operational efficiency incentive is enhanced under rate
cap plans in that utilities are able to maintain the benefits of their successful
cost saving measures (in the form of enhanced shareholder returns) for the
duration of the plan. This is in
contrast to traditional regulation in which the benefits of increased
operational efficiency to utility shareholders are essentially removed as soon
as rates are reset in periodic rate proceedings.
Thus,
the rate cap plans have been effective in mirroring competitive markets by
setting prices independent of the utility’s costs, and by allowing utilities to
benefit from their efficiency innovations or suffer losses as a result of
either inefficiencies, poor business decisions, or changes in the business
climate. At the same time, the
productivity offsets contained in the ARPs have worked to ensure that
ratepayers receive a fair share of potential operational savings regardless of
whether the utility’s actual performance produced such savings.
B. System
Reliability
There
are two areas of reliability issues: those involving the distribution network
and those involving the regional system.
Most reliability problems result from problems on the local distribution
network, such as wind damage, ice damage, lightening strikes, and motor vehicle
accidents. Regional problems, such as
the blackout that affected much of the Northeast on August 14, 2003, are rare
but can have a substantial impact.
1. Regional
Reliability
The regional
grid is designed to be able to recover from failures of generators or
transmission lines without widespread blackouts. However, on occasion (the August 14, 2003 blackout is an example)
these recovery operations are not invoked or prove to be inadequate. Since the major blackout in 1965, there have
been regional and national efforts to standardize planning criteria and
operating protocols under the auspices of the North American Electric
Reliability Council or NERC. Those
efforts are aimed at eliminating regional blackouts.
State and federal efforts to restructure the
electricity industry have resulted in the decentralization of decision-making
related to electric system reliability.
Prior to restructuring, integrated utilities controlled virtually all
aspects of power supply and reliability within their respective service
territories. Currently, responsibility
in the New England region is divided among a wider range of entities:
generators, transmission owners, electricity suppliers and ISO-NE. This decentralization, coupled with still
emerging roles of the various market players has, at least arguably, resulted
in a slowdown in investment, particularly in transmission facilities that could
help to maintain or improve regional reliability.
At present,
regional reliability concerns appear more applicable to regions other than New
England. Maine currently has a
substantial surplus of generation. This
means that, in the event of a system problem, electric service in Maine should
be maintained so long as the system reacts quickly enough to avoid an external
disruption to cascade into the State.[25] Moreover, except for specific load pockets,
there is generally excess generation capacity in New England.
Going
forward, ISO-NE can be expected to play an increasing role in ensuring adequate
regional reliability. This will occur
through market rules intended to maintain adequate generation resources in the
region, as well as through longer-term planning and oversight intended to
ensure that adequate transmission infrastructure is in place.
2. Distribution
Reliability
Multi-year rate cap plans provide powerful incentives to minimize costs that could result in the reduction of distribution system reliability. To counteract those incentives, the plans include service quality standards that utilities must satisfy to avoid financial penalty. The adoption of the CAIDI and SAIFI metrics with automatic penalty mechanisms results in enhanced financial incentives for utilities to provide appropriate reliability and a more