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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 effective and objective way to measure service quality than the
tools previously relied on by the Commission under traditional regulation. As the Commission has gathered
experience with these metrics, it has refined the service reliability
evaluation methods and techniques.
Specifically,
the Commission has recognized that insufficient investment and deterioration in
the utility’s plant might not be reflected in degradation of service until some
time in the future. Accordingly, the
Commission has substantially refined the service reliability information that
each utility must submit to the Commission each year. Currently, CMP must submit, as part of its annual ARP filing, a
distribution plant report which provides information on the age of the
utility’s distribution equipment and facilities, its construction budget for
the past two years, and actual construction spending for the prior year.[26]
The
Commission has also recognized that it is possible for a utility to maintain
acceptable service levels on a system-wide average basis, but allow service to
customers in certain areas (particularly less densely populated rural areas) to
deteriorate. As a result, BHE and CMP
are required, as part of their annual filings, to prepare and submit an Annual
Reliability Improvement Report which includes a service area specific analysis
of service reliability, an identification of the company’s worst circuits, an
analysis of each circuit’s problems and the planned and/or undertaken
improvements to address each problem.
These reports have enabled the Commission and the Public Advocate to
review service area specific problems and to engage in a constructive dialogue
with the utilities to ensure that such problems are addressed.
As
part of the Commission’s monitoring of service reliability issues, it has also
recognized that, with customers’ increased use of electronic equipment (such as
VCRs, digital clocks and computers), the quality of power provided to customers
has become more important in recent years.
Momentary power interruptions are, therefore, becoming more of a focus
of consumers’ perception of reliable electric service. While the impact of momentary interruptions
may at times be more of a nuisance than a serious problem, frequent occurrences
can damage equipment, erode public confidence, and increase the likelihood of
complaints to the utilities and to the Commission. In addition, power quality problems can have an adverse effect on
the State’s efforts to attract high-tech industries that are very sensitive to
such interruptions, as well as on the increasingly computer-dependent
operations of other commercial enterprises in Maine.
The Commission, therefore, convened a statewide
task force of interested stakeholders,[27]
referred to as the Power Quality Task Force (“PQTF”), to investigate
alternative service quality indicators and, where appropriate, to recommend new
indicators for measuring power quality service performance. The PQTF investigated whether a Momentary
Average Interruption Frequency Index (MAIFI)[28]
should be included as an SQI indicator, and recommended that a MAIFI standard not be established at this time. Instead, the PQTF recommended that each
utility collect specific service data for a two-year period which can then be
used to determine if MAIFI or some other metric should be adopted to assess the
quality of power provided by CMP, BHE and MPS.
The data will also be used to determine if a correlation exists between
customer satisfaction and momentary interruptions. If the decision is made to adopt a momentary outage metric, the
metric would be incorporated into the CMP and BHE ARPs. MPS does not currently have an alternative
rate plan, however, the metric could be considered for adoption independent of
a rate plan or as part of a future rate plan.
Finally,
recognizing that the evaluation of service quality and reliability is an
evolving and ongoing process, both the CMP ARP 2000 and the BHE ARP provide for
mid‑period reviews of the operation of the SQI mechanism. CMP’s mid‑period review was concluded
in December 2003, and included a change in the exemption criteria for the CAIDI
and SAIFI metrics. The exemption
criteria as originally approved excluded outages that affected 10% of customers
within portions of CMP’s territory from the metric calculations. The outage exemption mechanism in operation
had worked in an unintended manner to exclude minor outages and thus was not
properly tracking CMP’s service reliability.
The exemption criteria were therefore changed so that only outages which
affect 10% of CMP’s customers on an entire service territory basis would be
excluded.[29] BHE’s mid‑period review will occur
during 2004.[30]
The
Commission will continue to examine ways to improve the operation of the
service quality indices.
C. Energy
Efficiency
Under
the Commission’s stranded cost rate setting process, stranded cost rates are
set for a several-year period based on a forecast of sales. Because a utility’s stranded costs do not
vary with volume, after stranded costs are set , the utility has a strong
incentive to promote sales because all increases in sales flow directly to the
utility’s bottom line. While the
Commission retains the authority to reset stranded cost rates during the
stranded cost rate-setting period to correct substantial inaccuracies, any such
change can only be made on a prospective basis. Thus, during the time a case is being litigated to correct for
sales volume changes, the utility would retain the amounts collected from
ratepayers above those projected to be needed to recover stranded costs. During 2003, the Commission concluded an
investigation of CMP’s stranded costs to address the issue of higher than
projected sales.[31] Typical of traditional cost of service rate
setting, the proceeding was controversial and required a significant amount of
Commission staff and utility resources.
With
respect to ARP rate setting in effect for distribution delivery rates, the
incentive for utilities to promote electricity sales and to discourage energy
efficiency and conservation are magnified to some degree relative to
traditional regulation. As with
traditional regulation, a utility’s profits are a direct function of sales levels.
However, the inability of a utility under a rate cap plan to file for a rate
increase in response to increasing costs or decreasing revenues provides a
greater motivation for utilities to act to increase sales over the term of the
plan, as well as an enhanced financial conflict with conservation activities
that serve to reduce the consumption of electricity.
The Legislature, recognizing both that
utilities were no longer in the generation business and that there continued to
be strong disincentives regarding the conservation of electricity, transferred
the responsibility to administer energy efficiency and conservation programs
from the utilities to the Commission.
This dramatically changes the issue of regulatory responses to utility
financial incentives regarding energy efficiency and conservation. Utilities, either under traditional
regulation (stranded cost) or alternative regulation (distribution delivery)
still have the incentive to discourage conservation and promote consumption. However, utilities no longer carry out
ratepayer funded conservation measures and, thus, cannot act to hinder the
effectiveness of such programs through ineffective or non‑performance. The result is that the importance of
addressing the inherent disincentive that derives from the ratemaking process
through the adoption of alternative regulatory devices or changes to rate
design has been greatly diminished.
D. Rate Structures
When
utilities were vertically integrated and provided generation supply, it was
reasonable to rely on usage sensitive charges because a substantial amount of
utility costs varied with actual ratepayer consumption. After restructuring, utilities provide only
delivery service and each utility’s rates must recover only the costs
associated with delivery service and stranded costs. The costs to provide the delivery component of utility service
are generally fixed, at least in the shorter term. In the long run, T&D utility costs vary to some degree
because the sizing of facilities over the longer term depends on maximum
consumption (i.e., “peak load”) of customers.
Stranded costs are historic costs and, thus, do not vary with current consumption. Stranded costs, however, were incurred to provide generation service and, therefore, even though such costs do not vary with current usage, as a matter of equity, it may be argued that such costs should continue to be recovered through demand and energy charges because this tends to allocate costs to customer classes and to customers (in general, if not individually) according to their cost causation responsibilities.
The current usage-based delivery and stranded
cost rates have the effect of providing the incentive for utilities to promote
sales because additional sales translate into additional earnings. This is especially the case with respect to
stranded costs which do not vary at all with sales volume. The current T&D utility rate design
does, however, provide strong price signals for customer conservation because a
substantial portion of costs remain in usage sensitive charges. Thus, lower usage results in reduced
bills. It should also be noted that the
existence of stranded costs in T&D rates means that rates are actually
higher than the ongoing cost of service, resulting in greater incentives for
customers to conserve electricity or seek grid alternatives than would actually
be efficient if rates more accurately reflected the underlying costs.
During
2001, the Commission initiated an investigation to examine moving more T&D
utility costs into fixed charges.[32] The investigation focused on stranded costs
because there is little debate that, from an economic efficiency perspective,
such costs (which are sunk) should be recovered through fixed charges. However, the proceeding was controversial. Although utilities were generally supportive
of moving stranded costs into fixed charges, the intervenors generally opposed
the move. The basis for the opposition
was twofold: first, moving rates from usage sensitive to fixed charges would
reduce the incentive of consumers to conserve their electricity usage; and
second, the change would increase utility bills for low-use customers.[33] Ultimately, the case was resolved by a
stipulation that made only a very modest move to fixed charges, by targeting
expected rate decreases over several years only to energy charges.[34]
E. Economic
Development
Under both traditional and rate cap rate setting methodologies,
utilities have a strong incentive to promote economic development of any type
within their respective service territories.
Economic growth leads to increased sales, which results in increased
utility profits. Additionally, the
management of utilities, like that of any business, has an interest in
increasing the size of their business.
Utilities have no particular incentive to attract energy-efficient
business, as opposed to any other new enterprise (unless the utility views an
energy-efficient business to be more likely to be viable over the long-term).
The
financial incentive for utilities to promote economic development under
ARPs is magnified relative to traditional regulation due to the inability of a
utility to file for a rate increase under a rate cap plan. Generally, this magnified incentive would
make it more attractive for utilities to promote energy-intensive businesses.
This section
of the report presents and discusses regulatory mechanisms that can be used to
alter financial incentives of utilities.
A. Revenue
Decoupling
1. General Description
Revenue decoupling is a
form of ratemaking intended to remove the financial disincentive that utilities
have to engage in or support energy efficiency and conservation activities.[35] The mechanism also acts to remove the
financial incentive to promote increases in sales. Revenue decoupling works by severing the link between a utility’s
sales and its profits. This is
accomplished by pre-establishing a utility’s “allowed” revenues, which would
typically occur in a traditional rate case proceeding. These allowed revenues are periodically
compared to the utility’s actual revenues and the difference is tracked for
ratemaking purposes in a deferred account.
In the event actual revenues are greater than allowed revenues, the
difference is returned to ratepayers through a rate reduction. Conversely, if actual revenues are below
allowed revenues, the difference is collected by the utility through a
surcharge on rates.
2. Energy Efficiency Incentives
By
establishing a ratemaking process in which the revenue a utility ultimately
obtains is independent of sales levels, the financial disincentive that exists
under traditional and rate cap regulation to promote energy efficiency and
conservation, as well as the incentive to promote increased consumption, is removed
because profits are no longer a function of sales volume. Revenue decoupling does not, however,
provide any positive incentive for utilities to promote or support energy
efficiency or conservation programs; it only makes them financially neutral to
such activities.[36]
The implementation of revenue
decoupling would reduce a utility’s incentive to promote economic development
to some degree in that increased electricity consumption would not increase
profits. However, depending on the form
of revenue decoupling, the incentive in favor of increasing the number of
customers would either be enhanced or not affected.
3. Operational
Efficiency, Rates and Risks
Although revenue decoupling acts to ensure pre-specified levels of
revenue, it does not guarantee any level of profits. Thus, under revenue decoupling, a utility maintains its incentive
to cut costs or increase efficiency in operations. This incentive to minimize costs can be enhanced through a
multi-year revenue decoupling plan.
Such a plan would be similar to a multi-year rate cap plan in that
increased incentives for operational efficiencies occur as the result of an
inability of a utility to file a rate case through the period of the plan. Like a rate cap plan, a revenue decoupling
plan would include a formula (such as inflation minus productivity) by which
the allowed revenue would change on an annual basis, and could also include any
of the other typical attributes of a rate cap plan, such as service quality
standards and earning sharing mechanisms.
Revenue
decoupling mechanisms are not specific to revenue losses from efficiency or
conservation activities. Revenue
decoupling results in utilities being financially neutral to the impact on
sales levels (either sales decreases or increases) from any cause, most notably
economic conditions and the weather.
Thus, revenue decoupling has the effect of shifting the risks of
economic cycles and weather fluctuations from utilities to ratepayers. This impact combined with the revenue
accounting deferrals inherent in revenue decoupling results in increased rate
volatility and uncertainty relative to traditional or rate cap regulation.
There are, however, adjustments that can be made to
a revenue decoupling mechanism to reduce the shift of risks to ratepayers. For example, the allowed revenue under a
revenue cap could be normalized for weather or economic conditions, or allowed
revenue could be adjusted based on the number of customers (which would leave
utilities subject to economic conditions to some degree). The implementation of these types of
adjustments is complicated and would not act to completely avoid the shift of
risks onto ratepayers. Another mechanism
that would reduce the shift of risks to ratepayers, as well as lower rate volatility
impacts, is a limit on the amount of revenue that could be deferred for later
recovery. Such an approach, however,
would eliminate the incentive impact of the revenue decoupling once the
deferral limit was reached.
The
shifting of sales level risk to ratepayers that occurs with revenue decoupling
might be offset to some degree by a lower cost of capital for utilities that
could translate into some level of lower rates.
4. Maine’s Experience with Revenue
Decoupling
Maine has
experience with revenue decoupling. In
1991, the Commission adopted, on a three-year trial basis, a revenue decoupling
mechanism for CMP (referred to as “Electric Revenue Adjustment Mechanism” or
“ERAM”).[37] The “allowed” revenue was determined in a
rate case proceeding and adjusted annually based on changes in the utility’s
number of customers. Analyses before
the Commission at the time indicated that changes in the number of customers
were at least as good an indicator of CMP's costs as changes in sales
levels. CMP’s ERAM was not, however, a
multi-year plan, so CMP was free to file a rate case at any time to adjust its
“allowed” revenues.
CMP’s
ERAM quickly became controversial.
Around the time of its adoption, Maine, as well as the rest of New
England, was at the start of a serious recession that resulted in lower sales
levels. The lower sales levels caused
substantial revenue deferrals that CMP was ultimately entitled to recover. CMP filed a rate case in October of 1991
that would have increased rates at the time, but likely would have caused lower
amounts of revenue deferrals. However,
the rate case was withdrawn by agreement of the parties to avoid immediate rate
increases during bad economic times.[38]
By
the end of 1992, CMP’s ERAM deferral had reached $52 million. The consensus was that only a very small
portion of this amount was due to CMP’s conservation efforts and that the vast
majority of the deferral resulted from the economic recession. Thus, ERAM was increasingly viewed as a
mechanism that was shielding CMP against the economic impact of the recession,
rather than providing the intended energy efficiency and conservation incentive
impact. The situation was exacerbated
by a change in the financial accounting rules that limited the amount of time
that utilities could carry deferrals on their books.
Maine’s experiment with revenue cap regulation came
to an end on November 30, 1993 when ERAM was terminated by stipulation of the
parties.[39]
B. Lost Revenue Adjustments
1. General Description
Lost revenue adjustments
are a common mechanism employed to reduce utility disincentives to pursue
energy efficiency and conservation. The
mechanism works by estimating the amount of sales that a utility has lost as a
result of energy efficiency programs and reimbursing the utility for its lost
revenues. The reimbursement occurs
through an adjustment in utility rates.
The mechanism is considered an alternative to revenue decoupling and
could be implemented in conjunction with traditional or rate cap regulation. Lost
revenue adjustments are not designed to, and do not, impact utility
incentives to provide adequate system reliability.
2. Incentive
Impacts
The mechanism, if implemented accurately,[40] makes utilities financially neutral to lost sales resulting from energy efficiency programs. However, it does nothing to impact a utility’s incentive to promote increased sales, or to align a utility’s interests with a state’s efficiency objectives or efficiency activities by other entities for which they are not reimbursed under the mechanism. Moreover, the mechanism is relatively complex to administer, and measurement and evaluation issues are often controversial.
C. Incentive
Payments/Penalties
1. ROE Adjustments
Return on equity (ROE)
adjustments are a means to reward or penalize a utility for its
activities. The Commission has
substantial discretion to set a utility’s ROE within a reasonable range or
bandwidth. Thus, if a utility is found
to have acted in an exemplary fashion in the promotion of State policies, the
Commission could establish an ROE at the upper end of the reasonable
range. Conversely, if the Commission
finds that a utility has acted contrary to State policies, a lower ROE can be
established.
The mechanism can be used to provide utilities with
the incentive to promote energy efficiency and conservation, or to provide
appropriate system reliability. As
discussed above, the use of ROE adjustments is the primary tool under
traditional regulation to ensure that utilities act in a manner consistent with
their obligations, [41] but they can also be employed as part of rate cap or revenue
decoupling regulation. The application of ROE adjustments occurs in the context
of litigated proceedings, is subjective in nature, and is usually controversial.
2. Shared Savings
Shared savings mechanisms are used to provide
utilities with the incentive to aggressively pursue energy efficiency and
conservation programs. The mechanism
works by allowing utilities to “share” a pre-specified portion of the savings
achieved from their energy efficiency and conservation programs, thus linking a
utility’s profits to its conservation performance. The mechanism is not applicable to system reliability incentives.
Energy efficiency and conservation programs, assuming
that they are cost-effective, will cost less than a comparable amount of
supply. The difference between the cost
of the avoided supply and cost of the efficiency program represents overall
ratepayer savings. Under a shared
savings program, a utility is able to recover a portion of these savings
through an upward adjustment in its rates.
The mechanism is relatively complex to administer, and requires rigorous
measurement and long-term verification of achieved savings.
Shared savings programs do not remove the basic utility incentive to promote consumption or to discourage conservation. For this reason, a shared savings program is often adopted in conjunction with a lost revenue adjustment or a revenue decoupling mechanism.
D. Service
Quality Standards
As
discussed above, the Commission has incorporated service quality standards with
automatic penalty provisions as part of the alternative rate plans. In addition to penalizing a utility for
service that degrades below baseline standards, a service quality standard
mechanism could be designed to reward a utility for exceptional service
quality. Another possible variation
would be to adopt area specific standards within a utility’s service territory
and penalize (or reward) the utility based on its performance within portions
of its service territory. While this
approach has been suggested in prior Commission proceedings, the Commission has
not adopted it.
It is possible to use
service quality standards in the context of different rate‑setting
mechanisms, such as traditional rate-of-return regulation.
E. Direct
Pass-Through
1. General
Description
Direct pass-through of
utility costs is a ratemaking mechanism that allows utilities to receive
dollar-for-dollar recovery of certain categories of costs. The mechanism can be used to remove the
incentive utilities may have against making expenditures in certain areas. Under the general approach to ratemaking,
utilities do not receive dollar-for-dollar recovery of their expenditures. Instead, rates are set on a prospective
basis using historical costs. Direct pass-through of costs is an exception to
standard ratemaking that is appropriate in some circumstances. For example, particular costs that are
extremely volatile and outside the control of the utility have been candidates
for direct pass-through.[42] Additionally, utilities often recover the
costs of publicly mandated programs through direct ratepayer
pass-throughs. This is done to help
ensure that utilities do not under-fund such programs to enhance their bottom
line profits.
Utility expenditures on energy efficiency and
conservation programs in Maine have historically been subject to direct
pass-through rate recovery. This was
part of a longstanding regulatory attempt to counter utilities’ natural
inclination against spending money to reduce the use of its product. Utility expenditures on system reliability,
however, have generally not been subject to direct pass-throughs in that they
are considered a basic part of utility operations and not subject to special
ratemaking treatment. However, there
have been exceptions for costs resulting from unusually destructive storms,
such as the 1998 ice storm.
2. Incentive
Impacts
Direct pass-through of costs
removes the incentive utilities have to under-fund certain programs or projects
so as to enhance profits. However, any
time a category of costs is recovered on a dollar-for-dollar basis, there is no
financial incentive for the utility to be efficient or to minimize costs in conducting
the program or project.
1. General
Description
Maine ratepayers’ bills now
consist of both unregulated and regulated prices and, within the regulated
component, FERC jurisdictional and Maine jurisdictional rates. At the present time, all rates have usage
sensitive components. While it would be
possible to recover the entire PUC jurisdictional revenue requirement through
fixed charges, a significant portion of electricity bills would remain usage
sensitive.
2. Incentive
Impacts
The more a utility’s
costs are recovered through fixed charges, the less financial incentive it has
to promote sales or to discourage energy efficiency and conservation. [43] However, unless all of a utility’s costs are
recovered through fixed charges, some incentive to promote consumption on the
part of utilities will remain. A
movement towards a more fixed charge rate design would also reduce a utility’s
incentive to promote economic development to some degree since increased electricity
consumption would not increase profits.
However, increasing the number of utility customers would have a
positive impact on profits.
If
T&D utility rate design were changed so that it consisted entirely of fixed
charges, it would provide no financial incentive for customers to conserve
their usage of electricity. However,
because the supply portion of the electricity bill would continue to consist of
usage‑sensitive charges, there would still be some incentive for
consumers to conserve. However, the
motivation of consumers to conserve would be significantly reduced in that
approximately two thirds of electricity bills are comprised of T&D charges.
3. Rate
Impacts
Any time rate design is
altered some customers benefit through lower bills, while other customers are
subjected to higher bills. Therefore, a
primary consideration in any attempt to move to a more fixed rate design is
customer bill impacts. The movement to
a fixed rate design in particular would result in increases for customers with
relatively lower usage within a class, and decreases for customers with
relatively higher usage.
To
illustrate the bill impact effect, the following tables show the impact on
CMP’s residential and small business customers if all T&D costs (including
stranded costs)
were recovered through a fixed customer charge.
As the tables above
illustrate, if T&D charges were fixed, CMP residential customers would pay
a flat rate of $35.13 per month and small commercial customers would pay a flat
rate of $63.39 per month for T&D delivery service, and lower usage
customers in both classes would see significant bill increases.
The following tables show the number of customers in
CMP’s territory whose average monthly bill falls within various kWh ranges. A customer’s bill will vary by
month, so the level of bill
increase or decrease will vary by month.
However, these tables give an idea of the number of customers that will
experience bill increases or decreases of the sizes shown above. In general, it is reasonable to estimate
that, if the fixed rates described above were implemented, about half of
Maine’s residential customers would experience bill increases.
G. Summary of Alternatives
The following table summarizes the incentive
impacts of the various alternative regulatory tools discussed in this section,
as well as traditional regulation and the rate cap mechanism currently in place
in Maine.
Incentive Impacts
|
|
Electricity
Consumption |
Energy
Efficiency |
System
Reliability |
Operational
Efficiency |
Economic
Development |
|
Traditional Regulation |
Incentive
to Promote |
Incentive
to Discourage |
Possible
Incentive to Over Invest |
Little
Incentive to Maximize |
Incentive
to Promote |
|
Rate
Cap Regulation |
Enhanced
Incentive to Promote |
Enhanced
Incentive to Discourage |
Incentive
to Minimize Investment |
Enhanced
Incentive to Maximize |
Enhanced
Incentive to Promote |
|
Revenue
Decoupling with Rate of Return |
No
Incentive to Promote |
No
Incentive to Encourage |
Possible
Incentive to Over Invest |
Little
Incentive to Maximize |
Reduced
Incentive to Promote |
|
Revenue
Cap Regulation |
No
Incentive to Promote |
No
Incentive to Encourage |
Incentive
to Minimize Investment |
Enhanced
Incentive to Maximize |
Reduced
Incentive to Promote |
|
Fixed
Rate Design |
No
Incentive to Promote |
No
Incentive to Encourage |
No
Impact |
No
Impact |
No
Impact |
|
Lost
Revenue Adjustments |
Incentive
to Promote |
No
Incentive to Discourage (Utility Programs) |
No
Impact |
No
Impact |
No
Impact |
|
Shared
Savings |
Incentive
to Promote |
Reduced
Incentive to Discourage (Utility Programs) |
No
Impact |
No
Impact |
No
Impact |
|
ROE
Adjustments |
Reduced
Incentive to Act Contrary to State Policy |
Enhanced
Incentive to Promote State Policy |
Enhanced
Incentive to Provide Appropriate Reliability |
No
Impact |
Enhanced
Incentive to Promote State Policy (e.g.., Energy Efficient Business) |
|
Service
Quality Standards |
No
Impact |
No
Impact |
Enhanced
Incentive to Provide Adequate Reliability |
No
Impact |
No
Impact |
|
Direct
Pass‑Through |
No
Impact |
Reduced
Incentive to Discourage (Utility Programs) |
Enhanced
Incentive to Provide Adequate Reliability |
Little
Incentive to Maximize |
No
Impact |
V. OTHER
STATE MECHANISMS
The Commission
has 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 this
research are presented in this section of the report and summarized in the following
tables. The Commission was not able to
obtain information from every state and, accordingly, the presentation in this
section is based on those states for which information could be obtained.
A. Energy
Efficiency and Conservation
Many states employ a variety of mechanisms to
address the financial disincentive of utilities to reduce consumption through
energy efficiency and/or conservation.
The mechanisms most commonly used are performance incentives, shared
savings, and lost revenue adjustments.
Some states also employ a direct pass-through of costs and ROE
adjustments. A number of states
eliminated their conservation incentive mechanisms after their state restructured
the electric industry or removed the obligation of utilities to pursue conservation
and efficiency programs. The
Commission’s research revealed no state in which conservation incentive
mechanisms are applied to utilities under circumstances in which utilities are
not obligated to pursue efficiency and conservation programs.
A number of states adopted a revenue
decoupling mechanism in the past.
However, no state currently employs this type of mechanism. Decoupling mechanisms have been eliminated either
due to dissatisfaction with their operation or as a result of changes in the
industry structure. However, two states
(California and Montana) are currently considering the re-adoption of a
decoupling mechanism. A renewed effort
regarding conservation incentives in these states is a result of the failure of
restructuring efforts to produce effective retail competition.
Finally, the Commission is unaware of any
state that has moved to a fixed charge rate design as means of addressing
utility incentives regarding energy efficiency and conservation. However, New York has a pending
investigation of electricity delivery rate disincentives against the promotion
of energy efficiency, renewable technologies, and distributed generation.
The
following table presents a summary of other state energy efficiency and
conservation incentive mechanisms.
|
State |
Revenue Decoupling |
Lost Revenue Adjustment |
Shared Savings |
Performance Targets
Incentives/ Targets |
ROE Adjustments |
Direct Pass-through |
Mechanisms Eliminated * |
Non-utility
Efficiency Agency |
Revenue Decoupling in Past |
None |
|
Arkansas |
|
|
|
|
|
|
|
|
|
X |
|
Calif. |
|
|
X |
X |
|
|
|
|
X |
|
|
Colo. |
|
|
|
|
|
|
|
|
|
X |
|
Conn. |
|
|
|
X |
|
|
|
|
|
|
|
Delaware |
|
|
|
|
|
|
|
|
|
X |
|
Florida |
|
|
|
|
|
X |
|
|
X |
|
|
Illinois |
|
|
|
|
|
|
|
|
|
X |
|
Indiana |
|
X |
X |
X |
|
|
|
|
|
|
|
Iowa |
|
|
|
|
|
|
|
|
|
X |
|
Kansas |
|
|
|
|
X |
|
|
|
|
|
|
Kentucky |
|
X |
X |
|
|
|
|
|
X |
|
|
Mass. |
|
|
|
X |
|
|
|
|
|
|
|
Minn. |
|
|
|
X |
|
|
|
|
|
|
|
Missouri |
|
|
|
|
|
|
|
|
|
X |
|
Montana |
|
|
|
|
X |
|
|
|
X |
|
|
Nebraska |
|
|
|
|
|
|
|
|
|
X |
|
Nevada |
|
|
|
X |
|
|
|
|
|
|
|
New Jersey |
|
X |
|
X |
|
|
|
|
|
|
|
New York |
|
|
|
|
|
|
X |
X |
X |
|
|
Ohio |
|
|
|
|
|
|
X |
|
|
|
|
Oregon |
|
|
|
|
|
|
X |
X |
X |
|
|
Penn. |
|
|
|
|
|
|
|
|
|
X |
|
Rhode Island |
|
|
|
X |
|
|
|
|
|
|
|
Tenn. |
|
|
|
|
|
|
|
|
|
X |
|
Texas |
|
|
|
|
|
|
|
|
|
X |
|
Utah |
|
|
|
|
|
X |
|
|
X |
|
|
Vermont |
|
|
|
|
|
|
X |
X |
|
|
|
Virginia |
|
|
|
|
|
|
|
|
|
X |
|
Wash. |
|
|
|
X |
|
|
|
|
X |
|
|
Wisc. |
|
|
X |
|
|
|
|
X |
|
|
|
Wyoming |
|
|
|
|
|
|
|
|
|
X |
|
|
|
|
|
|
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|
|
|
|
* State had one or more efficiency mechanisms in the
past. These mechanisms were eliminated
after industry restructuring or when utility obligations to implement
efficiency programs were removed.
B. System
Reliability
The majority of states for which the
Commission was able to obtain information have no specific mechanism to address
the financial incentives for utilities to provide adequate system
reliability. However, service quality
standards that involve financial penalties for the failure to meet
pre-specified standards are common.
Some states do adjust ROEs or impose monetary penalties to address
service quality issues.
The following table presents a summary of
other state’s system reliability incentive mechanisms.
|
State |
Service
Quality Standards
Penalties |
Service
Quality Standards Rewards |
ROE
Adjustments |
Monetary
Penalties |
Direct
Pass-through |
None |
|
Arkansas |
|
|
X |
X |
|
|
|
California |
X |
|
|
|
|
|
|
Delaware |
|
|
|
X |
|
|
|
Florida |
X |
X |
|
|
|
|
|
Indiana |
|
|
|
|
|
X |
|
Iowa |
|
|
X |
|
|
X |
|
Kansas |
|
|
|
|
|
X |
|
Kentucky |
|
|
|
|
|
X |
|
Missouri |
|
|
|
|
|
X |
|
Montana |
|
|
|
|
|
X |
|
Nebraska |
|
|
|
|
|
X |
|
Nevada |
|
|
|
|
|
X |
|
New
York |
X |
|
|
|
|
|
|
Ohio |
|
|
|
|
|
X |
|
Pennsylvania |
|
|
|
X |
|
|
|
Tennessee |
|
|
|
|
|
X |
|
Texas |
|
|
X |
|
|
|
|
Utah |
|
|
|
|
|
X |
|
Vermont |
X |
|
|
|
|
|
|
Virginia |
|
|
|
|
|
X |
|
Washington |
X |
|
|
|
|
|
|
Wisconsin |
|
|
|
|
|
X |
|
Wyoming |
|
|
|
|
|
X |
|
|
|
|
|
|
|
|
As
required by the Legislature, this report covers utility incentives with respect
to two distinct areas: system reliability and energy efficiency. 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 of system reliability and ratepayer
cost. Accordingly, no major changes to
the regulatory scheme should occur 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, as discussed in this section of the
report, 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, in the following section, we have outlined and evaluated
several alternative approaches if the Legislature decides that public policy
requires that current financial incentives should be altered.
A. Recommended
Regulatory Approach
The
Commission recommends that no fundamental changes be made to the current
regulatory structure to alter utility financial incentives.
1. Rate
Cap Regulation
Multi-year rate cap plans (which have been in place
for CMP since 1995) have proven to be extremely successful in satisfying their
objectives. In effect, rate cap plans
mirror the competitive market by providing strong incentives for utilities to
increase efficiencies in their operations and lower their costs of providing
service, which have the effect of keeping rates as low as possible.
Rate caps were initially adopted in Maine in response to a series of frequent, unpredictable rate increases. The overarching goal of rate cap regulation was, and continues to be, the minimization of rates and rate volatility. Maine has high electric rates relative to other states. High electricity rates and rate level unpredictability have a significant negative impact on the State’s residents and businesses and on economic development. Thus, the minimization of rates and the maintenance of rate predictability and stability, in the Commission’s view, are high priorities for the State’s regulatory system. As discussed in Section III of this report, Maine’s implementation of rate cap regulation has satisfied its primary goals.[44] Moreover, rate cap plans have improved the regulation of service reliability through the creation of systematic and objective SQIs. While such plans do act to enhance a utility’s incentive to promote consumption relative to traditional regulation, the enhanced incentive is a matter of degree, in that utilities under traditional regulation always had a powerful incentive to promote sales.
The Commission
recommends that multi-year rate cap plans remain the basic regulatory approach
for Maine’s T&D utilities’ distribution delivery rates.
2. System Reliability Mechanisms
System reliability is essentially a function of the amount of money spent on facilities and maintenance. Greater reliability can always be achieved, but it would be at a cost to ratepayers. Thus, the question of the proper level of system reliability is one of balancing the reliable supply of power with cost. The Commission’s view is that, as a general matter, Maine has achieved a reasonable balance of reliability and cost.[45] This does not mean that there are no problems or concerns. The Commission must remain diligent to ensure that Maine consumers have adequate and reliable electric service at a reasonable cost.
The use of service quality standards should remain the primary regulatory means to ensure adequate reliability. As discussed above, service quality standards represent a vast improvement over the traditional regulatory approach to ensuring a proper level of system reliability and providing utilities with appropriate financial incentives. The use of service quality standards allows the Commission to monitor system reliability in a more systematic and comprehensive manner, and results in direct financial consequences if utilities fail to provide adequate service. The Commission will continue it efforts to refine the service quality standards in ways that improve their operation. Refined service quality mechanisms that the Commission may consider in future proceedings would include service area specific CAIDI and SAIFI targets, a metric which measures momentary interruptions (such as MAIFI), and a mechanism to reward superior service by expanding the earnings “dead-band” which would allow the utility to retain additional profits realized through efficiencies without penalizing ratepayers by increasing rates. In addition to service quality standards, the Commission maintains its ability, as well as its obligation, to respond to any indication (such as through customer complaints) of a reliability problem anywhere in the State by initiating investigations and ordering utilities to remedy the situation in a timely fashion.
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.
3. Energy
Efficiency Mechanisms
As discussed above, rate cap regulation does give utilities financial incentives to promote the consumption of electricity and to discourage energy efficiency and conservation. However, Maine’s T&D utilities no longer have the obligation to undertake energy efficiency and demand side management programs. The elimination of this obligation makes the incentive issue much less critical because utilities are no longer required to design and conduct programs that, if they succeed, reduce their profits. The concern under the current environment is the motivation of utilities to act contrary to the State’s efficiency and conservation policies primarily through the promotion of consumption.
When Maine’s utilities were under the legal
obligation to pursue cost-effective conservation measures, the conflicting
incentives were of paramount concern.
Any system in which an entity’s financial interests are contrary to its
legally mandated activities is problematic.
Although utilities in Maine accepted their obligations to varying
degrees, the Commission was required to continually monitor utility operations
to ensure that they were pursuing appropriate efficiency and conservation
measures.
This situation no longer exists in Maine. Pursuant to the recently enacted Conservation Act,[46] state-wide ratepayer funded efficiency and conservation programs are now developed and implemented by the Commission and utilities properly have no role.
The current situation is that utilities, like any other business, have the incentive to promote their product. Therefore, it is not surprising that CMP actively advertises the use of electricity (e.g. air conditioning and lighting promotional advertising).[47] However, in a similar manner, oil and propane dealers promote the use of their product, and retail outlets promote the sale and use of appliances, such as air conditioners. The Commission does not view this situation as necessarily improper. As a general matter, it is appropriate for private businesses to pursue the growth of their business and profits, while government acts to promote the public interest through activities such as the sponsorship of energy efficiency and conservation programs.[48]
As mentioned, the Commission has information suggesting that utility activity to promote the consumption of electricity has had limited effect. Through information provided by CMP in a recent Commission proceeding, it appears that CMP’s air conditioning ads have had only a very modest impact on its revenues. This modest impact of utility promotional efforts must be weighed against the potential adverse impacts and unintended consequences that may result from efforts to fundamentally alter the State’s current regulatory framework. The Commission believes that a better approach to supporting the State’s policy in favor of energy efficiency and conservation is to maintain an effective and adequately funded state-wide program in which efforts are made to directly affect the actions and motivations of electricity consumers.
The Commission does not recommend that regulatory mechanisms be adopted to alter utilities’ current incentives with respect to electricity consumption and energy efficiency.
4. Rate
Design
T&D utilities’ current underlying costs vary less with usage than is reflected in the current rate design. Thus, T&D utility rate design should provide for more cost recovery through fixed and demand (kW) charges relative to energy (kWh) charges. However, as illustrated in section IV of this report, a movement to a completely fixed rate design would have substantial rate impacts on a large number of the State’s consumers. Customers that currently consume relatively low amounts of electricity would have substantial bill increases, while those that use a lot of electricity would experience substantial bill decreases. In addition, the adoption of a fixed rate design would significantly reduce price signals for customers to conserve and could thus promote additional consumption (although the generation portion of the bill is likely to remain usage sensitive and continue to provide some price signals for conservation). In deciding whether to go to a completely fixed rate design, the significant reduction in consumer price signals for conservation and the possible stimulus of increased consumption should be balanced against an assessment of the effectiveness of utility promotional activities.
In addition, it is not clear that a completely fixed rate design is consistent with general ratemaking principles. [49] First, T&D costs are likely to be affected by consumer usage (e.g., total demand) in that those customers that consume more electricity tend to require larger and more costly T&D facilities to serve. Moreover, an equitable design of stranded cost rates would have larger customers paying a higher amount because stranded costs (which are generation-related costs) were incurred based on customers’ capacity and energy needs.
Based on principles of economic efficiency and cost causation, it is likely that the Commission will continue to move in the direction of reduced energy (kWh) charges and increased fixed and demand (kW) charges. This may occur through targeting rate decreases to energy charges as has occurred in the recent past. This approach has the benefit of moving away from T&D energy charges without increasing the bills of the State’s electricity consumers. However, without specific legislative direction, a completely (or even predominantly) fixed rate design is not likely to occur over the near term.
The Commission
recommends against the adoption of a fixed charge rate design for the primary
purpose of removing utility incentives to promote electricity consumption.
B. Alternative Approaches
As discussed above, the Commission does not recommend that any fundamental changes to the State’s regulatory framework be made to alter T&D utility incentives. However, if the Legislature determines that mechanisms should be employed to change utility incentives with respect to energy efficiency or system reliability, this section discusses approaches that should be considered.[50]
Overall
the Commission has ample statutory authority to implement the ratemaking or
rate design incentive mechanisms discussed in this section. In particular, sections 3195 and 3155-A of
Title 35-A provide specific authority for the Commission to adopt
rate-adjustment or rate design mechanisms to promote utility operational and
energy efficiency. However, as
explained, the Commission is not inclined to adopt the alternative approaches
discussed below without specific legislative direction.
1. 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.[51] The Commission strongly prefers this
approach over fundamental changes to the regulatory framework (e.g., adoption
of revenue decoupling in place of rate caps) because a “correct” rate design
for T&D utilities would likely include a substantial amount of cost
recovery through fixed charges and there are less likely to be unforeseen
consequences.[52]
Movement
to a fixed charge rate design would involve substantial bill impacts for many
customers. Accordingly, the Legislature
should consider mandating that the rate design change occur gradually over time
(perhaps by setting annual percentage or dollar caps on bill increases).
2. Revenue Reconciliation Stranded Cost Rate-Setting
As discussed in sections II and III of this report, stranded costs have not been made the subject of incentive or rate cap regulation and are generally governed by traditional ratemaking principles. In addition, the level of stranded costs do not vary with volume and increases in sales go directly to the utility’s bottom line. Therefore, current stranded cost ratemaking provides utilities with a strong incentive to promote sales.
While stranded costs do not vary with volume, many stranded cost elements are unknown at the time that stranded cost rates are set. As a result, the Commission has in past stranded cost cases issued a number of accounting orders which have allowed the utilities to defer for future recovery any differences between the amounts allowed in rates for specific items and the actual costs of such items when incurred. While the Commission has authorized a true-up approach for specific cost items, it appears that the language of 35-A M.R.S.A. § 3208 might not permit a reconciliation of stranded cost sales.[53] This issue was discussed during CMP’s last stranded cost rate setting proceeding, but was not pursued due to uncertainty concerning the Commission’s authority.
Given the circumstances
surrounding stranded cost ratemaking (stranded costs are not generally subject
to reduction through operating efficiencies, they do not vary with volume, and
a number of cost items in the past have been reconciled), it might be
appropriate to reconcile stranded cost rates for variations in sales and costs
projections. 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 a revenue reconciliation mechanism
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 T&D costs
would continue to be recovered through usage sensitive charges.
3. ROE
Adjustment Mechanism
A mechanism whereby a utility’s ROE is adjusted, either up or down, based on its performance in specified areas can be an effective means to impact incentives. Under such a mechanism, the Commission would predetermine a reasonable range for a utility’s ROE. For example, such a range might be between 9% and 11%.[54] The Commission would then periodically review a utility’s performance in certain areas to determine whether its prior activities warrant either a movement to the upper or lower end of the ROE range. The periodic review might occur on a pre-set schedule (e.g. every 2 years) or upon petition of a party. The areas of review would presumably be actions with respect to the promotion of energy efficiency and the provision of reliable service, but could include other activities.[55]
Illustrations of actions that might trigger an ROE adjustment under this mechanism follow:
-A utility violates State energy policy by using deceptive or misleading advertising to promote the inefficient use of electricity.
ROE is reduced.
-A utility acts consistent with State energy policy by acting to induce new energy efficient businesses to locate in the State.
ROE is increased.
-A utility acts to take advantage of a little-used new technology that enhances system reliability at a relatively low cost.
ROE is increased.
-A utility does not take reasonable steps to maintain sufficient reliability in a remote area of the State.
ROE is decreased.
The mechanism is subjective by its nature. The Commission would make a determination based primarily on its expert judgment. Thus, the periodic reviews, which would occur in litigated proceedings, are likely to be controversial and consume significant resources. Adjustments would likely occur rarely, only upon especially egregious or exemplary behavior.
The Commission does not favor this approach because it is inconsistent with current rate plans and implementation is likely to be extremely difficult. However, if the Legislature so mandates, an ROE adjustment mechanism could be made part of a multi-year rate plan with rate adjustments occurring as part of the annual ARP reviews.
4. 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. Under a multi-year revenue cap, the utility’s “allowed” revenues would be subject to an index constructed to provide the utility with the opportunity to earn reasonable returns. This means that, similar to the current rate cap plans, the index would account for inflation and a reasonable level of productivity.
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. Moreover, a revenue cap plan can be designed to minimize the shift of revenue fluctuation risks from causes other than energy efficiency measures. In particular, attempts can be made to minimize the shift of risks from changes in economic activity and weather from the utility to ratepayers. This can occur through use of economic activity and weather normalization techniques.[56] Although often controversial, weather normalization techniques are quite common in the forecasts of utility sales. However, techniques to normalize for the economy are not common and it would be extremely difficult to distinguish between sales changes related to the economy and sales changes related to efficiency measures. Although normalization techniques can help lower risk transfers, they are imprecise and would not completely prevent the transfer of risks. However, they would reduce the shift of risks to some degree and, consequently, the rate volatility that would result from revenue cap plan.
The Commission has great reluctance regarding the adoption of any type of revenue decoupling mechanism. Although the mechanism has theoretical appeal, the Commission has substantial concern over unintended consequences that may accompany the adoption of a regulatory structure which is so dependent on unpredictable events. Such unintended consequences rapidly developed with the Commission’s experiment with ERAM in the early 1990s and, as discussed in section V of this report, no state currently has a revenue decoupling mechanism (although several states had adopted such mechanisms in the past). The Commission urges great caution in abandoning the current regulatory framework, which is generally working as intended, in favor of an unproven mechanism so as to address an incentive issue that may not be of great consequence.
5. 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 obviously raise First Amendment issues. The Commission has not analyzed those issues, but it is conceivable that if the Legislature finds electricity consumption to be a substantial public concern (e.g., threat to public health), some restrictions on its promotion may be legally permissible.
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. For example, a requirement can be adopted that all electricity promotional advertising includes information on the environmental impacts of electricity consumption. Such a requirement, of course, would raise a difficult question: why should the Legislature single out electricity from other products (such as gasoline or heating oil) that also provide significant benefits while arguably damaging the environment? Without a satisfactory answer, those promoting electric consumption could reasonably claim unwarranted discrimination.
The Commission emphasizes that it does not recommend such an approach, but offers the concept if utility promotional advertising is the major concern underlying this examination of utility incentives.
[1] P.L.
2003, ch. 219.
[2] The
Commission views the terminology “security and robustness” to essentially mean
“reliability” of the system, rather than protection against terrorist
attacks. The Commission uses the term
“reliability” throughout this report.
[3] Inquiry
into Incentives to Promote Energy Efficiency and Security of the Electric Grid,
Docket No. 2003-423 (June 18, 2003).
[4] The
following entities provided input and comment during the Commission’s
investigation: Public Advocate, Central Maine Power Company, Bangor
Hydro-Electric Company and Maine Public Service Company.
[5] Under
traditional regulation, utilities are not permitted to recover costs from
ratepayers that the Commission finds to have been imprudently incurred.
[6] For
purposes of this report, “fixed charge” or “fixed rate design” means a pre-set
monthly charge that does not vary with customer energy (kWh) usage or total
customer demand (kW).
[7] 35-A
M.R.S.A. §§ 3151-3155.
[8] This
would occur when the rate-of-return allowed by the regulatory commission
exceeds the capital market rates and is referred to as the Averech-Johnson
effect.
[9] If a
utility is in financial trouble, it may defer maintenance or be unable to raise
capital for investment.
[10] This was
the case as long as the utilities’ rates were greater than their marginal cost
of production, a cost relationship that has existed since the late 1980s.
[11] This is a consequence of the
recovery of a substantial portion of utility costs through usage sensitive
rates (i.e. per kilowatt-hour charges).
The issue of moving towards greater use of fixed rates is discussed in
sections IV and VI of this report.
[12] Central
Maine Power Company, Proposed Increase in Rates, Docket
No. 92‑345 at 130 (Dec. 14, 1993).
[13] Central
Maine Power Company, Proposed Increase in Rates, Docket No. 92‑345(II)
(Jan. 10, 1995).
[14]These are:
CMP, Bangor Hydro-Electric Company (“BHE”) and Maine Public Service Company
(“MPS”).
[15] The
Commission, as part of the New England Conference of Public Utility
Commissioners (“NECPUC”), is opposing increases in returns (which translate
into increased rates) as a means to induce utilities to invest in transmission
on the grounds that utilities already have the lawful obligation to maintain a
reliable system and there has been no showing that higher returns are necessary
to raise capital.
[16] For
example, transmission is about 15% of CMP’s total T&D rate.
[17] 35-A
M.R.S.A. § 3208.
[18] Central
Maine Power Company, Request for Approval of Alternative Rate Plan
(Post-Merger), “ARP 2000,” Docket No. 99-666 (Nov. 16, 2000).
[19] Bangor
Hydro-Electric Company, Request for Approval of Alternative Rate Plan, Docket
No. 2001-410 (June 11, 2002).
[20] Maine
Public Service Company, Request for Approval of Alternative Rate Plan, Docket
No. 2003-085 (Sept. 3, 2003).
[21] As a consequence, the Commission considered and
adopted many of the mechanisms discussed in section IV of this report to combat
the utilities’ inherent financial disincentive
regarding efficiency and conservation.
These include ROE adjustments, direct pass-throughs, revenue decoupling,
shared savings, and DSM targets.
[22] P.L. 2001, ch. 624 (codified at
35-A M.R.S.A. § 3211-A).
[23] See,
Public Utilities Commission, Investigation Into Central Maine Power Company,
Ratepayer Complaints, Docket No. 92-078 (Aug. 6, 1992).
[24]
Additionally, CMP’s first ARP prevented a large amount of Maine Yankee shutdown
costs from being recovered from ratepayers.
[25]
Interestingly, Maine was one of the few Northeastern states which was not part
of the seminal 1965 blackout. Oral
history has it that the Maine operator was able to isolate Maine from the rest
of region quickly enough to avoid a major blackout.
[26] In the
context of reviewing BHE’s SQI, the Commission has also requested such data
from BHE.
[27] The task
force includes Commission staff members, the Public Advocate, and
representatives of CMP, BHE and MPS.
[28] MAIFI is a measure of the number of momentary
interruptions on an electric utility system.
These events may occur as a precursor to a sustained interruption (which
is captured in the other indices) or may be isolated events that are resolved by
the automatic operation of resoling devices or other protection devices on the
system. MAIFI is calculated by dividing
the total number of customer momentary interruptions by the total number of
customers served.
[29]
Mid-Period Review Investigation of CMP’s ARP 2000 Service Quality Indices, Docket No.
2002-445 (Dec. 12, 2003).
[30] It should
also be noted that, in addition to service quality standards, the Commission
continues to monitor the performance of utilities with respect to system
reliability. For example, after an ice
storm in 2002, the Commission initiated an investigation of the resulting power
outages and adopted numerous measures to improve utility response to storm and
other emergency situations. Investigation
into the Adequacy of Utility Services in Maine During Power Outages, Docket
No. 2002-151.
[31]
Investigation of Central Maine Power Company’s Stranded Cost Rates and Request
for an Accounting Order, Docket No. 2002-770 (June 20, 2003).
[32] Investigation
of Rate Design of Transmission and Distribution, Docket No. 2001-245.
[33] The
opposition came primarily from the Public Advocate and the Natural Resources
Counsel of Maine. In recent comments
provided to the Commission during its incentives investigation, the Public
Advocate indicated that he is not opposed to a fixed charge rate design in
concept, but believes that the resulting bill impacts for low use customers
would be “entirely unacceptable.”
[34] Rate
decreases were also targeted to winter charges in an effort to reduce the
seasonal differentiation.
[35] The implementation of revenue decoupling would have no significant impact on utility financial incentives to provide adequate system reliability relative to traditional or rate cap regulation.
[36]
Mechanisms to provide utilities with positive incentives to promote energy
efficiency and conservation are discussed below.
[37] Investigation
of Chapter 382 Filing of Central Maine Power Company, Order, Docket No.
90-085 (May 7, 1991). As discussed,
because a revenue cap alone does not provide a positive incentive for a utility
to pursue conservation, the Commission also adopted a shared savings program in
which CMP would be reimbursed for a portion of the savings from its
conservation programs. Such shared
savings programs are discussed below.
[38] Proposed
Increase in Rates, Order Granting Motion to Withdraw Proceeding, Docket No.
91-174 (Jan. 10, 1992).
[39] Consideration
of Issues Concerning ERAM-Per-Customer for Central Maine Power Company, Order
Approving Stipulation, Docket No. 90-085-A (February 5, 1993). After the termination of ERAM, the
Commission’s efforts regarding incentive regulation moved to the development of
rate cap regulation.
[40] Lost
revenue adjustments are often criticized in that they create an incentive for
utilities to make it appear that their programs are saving energy, when they
are actually ineffective. This results
in a windfall through the reimbursement of lost revenues that were never in
fact lost.
[41] The
Commission has used ROE adjustments in the past to both reward and penalize
utilities.
[42] For many
years, utilities were allowed a direct pass-through of their fuel costs
(primarily oil) pursuant to this rationale.
This practice came to end for CMP with the adoption of the 1995 ARP.
[43] The
recovery of a greater portion of costs through fixed charges would also reduce
a utility’s risk exposure which should lower its cost of capital.
[44] The
Commission notes that some of the success of rate plans in minimizing rates and
maintaining stability is attributable to several years of relatively low
inflation.
[45] The
Public Advocate has expressed a similar opinion in comments provided in this
investigation.
[46] As mentioned above, the
Conservation Act transferred to the Commission the responsibilities to develop
and implement state-wide efficiency and conservation programs. That Act provides the Commission with ample
authority to support energy efficiency initiatives in the State (within
statutory funding constraints).
[47] Pursuant
to Commission rule (Chapter 83), utilities are prohibited from recovering the
costs of promotional activities from ratepayers.
[48]
Electricity production is generally viewed as having significant environmental
impacts. (For example, NEPOOL has
calculated the 2001 regional average emission rates as: SO2 – 4.9
lbs/mWh, NOx – 1.7 lbs/mWh, and CO2 – 1394 lbs/mWh). Potential environmental impacts and their
effect on the State and its residents are appropriate grounds for government
intervention to increase energy efficiency.
[49] Substantial analyses of the cost structures of Maine’s T&D utilities would be required before any determination of a “correct” rate design could be made.
[50]
Some mechanisms used in other states would be
questionable at best in Maine where T&D utilities have no obligation to
implement conservation programs. These
include lost revenue adjustments and shared savings programs. It appears improper to reimburse utilities
for lost sales or to reward them with a percentage of savings with respect to
efficiency programs that have nothing to do with utility activities.
[51] As a
general matter, the Commission’s view is that specific rate design
determinations should be made by the Commission pursuant to general ratemaking
principles. The suggestion that the
Legislature mandate a particular rate design is made only in the context of a
legislative decision that utility financial incentives to promote the
consumption of electricity be removed.
In that a case, a legislative mandate regarding a specific rate design
would be appropriate.
[52] A
completely fixed rate design would result in a significant reduction of
financial risk for utilities.
Accordingly, a movement towards fixed rates should be accompanied by a
review of utilities’ cost of capital used for ratemaking purposes.
[53] 35-A M.R.S.A. § 3208(6)
provides: “When correcting stranded cost estimates and adjusting stranded cost
charges, the Commission shall make any change effective only prospectively and
may not reconcile past estimates to reflect actual values.
[54] An ROE range of 200 basis points should be large enough to get a utility’s attention. For example, a reduction of 100 basis points for CMP would amount to a revenue loss in the range of $7 million.
[55] Direct pass through of costs can
also be used in conjunction with ROE adjustments. For example, if a utility makes an investment in cost-effective
new technologies that results in enhanced system reliability, it can be allowed
to defer the expense for dollar-for-dollar recovery.
[56] For
example, normalization techniques might seek to estimate that each additional
degree day results in X amount of additional electricity sales or that a
percentage increase in the gross state product results in Y amount of
additional sales.