New Hampshire Public Utilities Commission
DR 96-150
ELECTRIC UTILITY RESTRUCTURING
ORDER ON REQUESTS FOR REHEARING, RECONSIDERATION
AND CLARIFICATION
ORDER NO. 22,875
March 20, 1998
TABLE OF CONTENTS
I. INTRODUCTION. . . . . . . . . . . . . . . . . . . . . . . . 1
II. PROCEDURAL HISTORY. . . . . . . . . . . . . . . . . . . . . 3
III. DISCUSSION . . . . . . . . . . . . . . . . . . . . . . . . 5
A. Procedural Matters . . . . . . . . . . . . . . . . . . 5
1. Rehearing Requests - Procedural Matters. . . . . 5
2. Commission Conclusions - Procedural Matters. . . 6
B. Nature of the Plan . . . . . . . . . . . . . . . . . . 7
C. General Policy Considerations. . . . . . . . . . . . . 9
D. Open Access Requirements . . . . . . . . . . . . . . .10
E. Rate Unbundling Requirement. . . . . . . . . . . . . .11
F. Scope of Unbundled Services. . . . . . . . . . . . . .13
1. Rehearing and Clarification Requests - Unbundled
Services . . . . . . . . . . . . . . . . . . . .13
2. Commission Conclusions - Unbundled Services. . .15
a. Metering and Billing . . . . . . . . .15
c. Cost Recovery Issues . . . . . . . . .19
d. Acceptance and Installation Standards.20
G. Vertical Market Power. . . . . . . . . . . . . . . . .20
1. Rehearing Requests - Vertical Market Power . . .21
2. Commission Conclusions - Vertical Market Power .23
H. Trade Name Prohibition . . . . . . . . . . . . . . . .26
I. Regulation of Distribution Services. . . . . . . . . .28
1. Rehearing Requests - Regulation of Distribution
Services . . . . . . . . . . . . . . . . . . .29
2. Commission Conclusions - Regulation of
Distribution Services. . . . . . . . . . . . . .30
J. Regulation of Retail Transmission Services . . . . . .30
1. Rehearing Requests - Retail Transmission Services 31
2. Commission Conclusions - Retail Transmission
Services . . . . . . . . . . . . . . . . . . . .32
K. Interim Stranded Cost Recovery . . . . . . . . . . . .35
1. Rehearing Requests - Interim Stranded Costs. . .39
a. ISC Charge Methodology . . . . . . . .39
b. "Takings" Arguments. . . . . . . . . .39
c. Federal Power Act/Preemption Claims. .42
2. Commission Conclusions - Interim Stranded Costs.43
a. Introductory Comments. . . . . . . . .43
b. "Takings" Claims . . . . . . . . . . .48
c. Federal Power Act/Preemption Claims. .55
3. Rehearing Requests - Decommissioning Costs . . .55
4. Commission Conclusions - Decommissioning Costs .56
5. Rehearing Requests - Exit Fees . . . . . . . . .58
6. Commission Conclusions - Exit Fees . . . . . . .59
7. Rehearing Requests - QF Costs. . . . . . . . . .60
8. Commission Conclusions - QF Costs. . . . . . . .61
L. Special Contracts. . . . . . . . . . . . . . . . . . .61
1. Rehearing Requests . . . . . . . . . . . . . . .62
2. Commission Conclusions - Special Contracts . . .62
M. Default Power Service. . . . . . . . . . . . . . . . .63
1. Rehearing Requests - Default Service . . . . . .64
2. Commission Conclusions - Default Power Service .64
N. Transition Service . . . . . . . . . . . . . . . . . .67
1. Comments on Transition Service . . . . . . . . .67
a. Nature of the Service. . . . . . . . .68
b. Eligibility. . . . . . . . . . . . . .68
c. The Need for Transition Service. . . .69
d. Power Supply Issues. . . . . . . . . .70
e. Administration . . . . . . . . . . . .71
f. Implementation Issues. . . . . . . . .72
2. Commission Conclusions - Transition Service. . .72
O. Energy Efficiency. . . . . . . . . . . . . . . . . . .75
1. Rehearing Requests - Energy Efficiency . . . . .76
2. Comments on Energy Efficiency and Other Public
Policy Issues. . . . . . . . . . . . . . . . . .78
a. Market Barriers. . . . . . . . . . . .78
b. Market-Based Incentives. . . . . . . .80
c. Cost-Effectiveness Test. . . . . . . .80
d. Program Administration . . . . . . . .81
e. Impact on Near-Term Rate Relief. . . .81
3. Commission Conclusions - Energy Efficiency and
Other Public Policy Issues . . . . . . . . . . .82
P. Supplier Registration. . . . . . . . . . . . . . . . .86
Q. Public Education Plan. . . . . . . . . . . . . . . . .87
IV. CONCLUSION. . . . . . . . . . . . . . . . . . . . . . . . .88
APPENDIX A . . . . . . . . . . . . . . . . . . . . . . . . . . .90
UPDATE ON REGIONAL ACTIVITIES: NEPOOL REFORM. . . . . . . . . .90
APPENDIX B . . . . . . . . . . . . . . . . . . . . . . . . . . .96
SUMMARY OF WORKING GROUP ACTIVITIES . . . . . . . . . . . . . .96
Supplier Registration Working Group. . . . . . . . . . . .96
Public Education Working Group . . . . . . . . . . . . . .97
Low Income Working Group . . . . . . . . . . . . . . . . 100
Electronic Data Interchange Working Group. . . . . . . . 102
Metering Working Group . . . . . . . . . . . . . . . . . 104
Disclosure of Resource Mix and Environmental
Characteristics of Power Working Group. . . . . . . 106
APPENDIX C . . . . . . . . . . . . . . . . . . . . . . . . . . 110
LIST OF PARTIES REQUESTING REHEARING, RECONSIDERATION OR
CLARIFICATION. . . . . . . . . . . . . . . . . . . . . . 110
APPENDIX D . . . . . . . . . . . . . . . . . . . . . . . . . . 111
REVISED COMPLIANCE FILING REQUIREMENTS. . . . . . . . . . . . 111
DR 96-150
ELECTRIC UTILITY RESTRUCTURING
ORDER ON REQUESTS FOR REHEARING, RECONSIDERATION
AND CLARIFICATION
O R D E R N O. 22,875
March 20, 1998
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1. INTRODUCTION
On February 28, 1997, the New Hampshire Public Utilities
Commission (Commission) issued a Statewide Electric Utility
Restructuring Plan (the Plan) and five related interim stranded
cost orders (ISC orders) pursuant to RSA 374-F. The Plan and
ISC orders implemented the policies of RSA 374-F by, inter alia,
requiring electric utilities to provide unbundled, open access
delivery services so that retail customers would have the ability
to purchase electricity from competitive suppliers. Under RSA
374-F:4, I, New Hampshire consumers must have retail access no
later than July 1, 1998. The Plan was designed to achieve
three primary objectives: first, it articulated the Commission's
general blueprint to implement RSA 374-F; second, it announced
generic policy statements consistent with the Commission's
delegated authority under RSA 374-F; and third, the Plan
established utility compliance filing requirements pursuant to
RSA 374-F:4, III. The Plan also established voluntary working
groups to make further recommendations to the Commission on how
to implement particular policy decisions.
In conjunction with the Plan, the Commission issued a legal
analysis that addressed numerous matters, including claims by
utilities that the Commission's authority to implement RSA 374-F
was limited by various sources of State and federal law. Among
the issues addressed in the Commission's legal analysis were
those concerning implementation of the Legislature's stranded
cost policies, the unbundling of utility services and state-
federal jurisdictional issues regarding the provision of retail
transmission.
The ISC orders applied the stranded cost policies set forth
in RSA 374-F to each utility based upon a particular cost
recovery mechanism articulated in the Plan. This mechanism
relied on a "benchmark" approach for setting interim stranded
cost charges that compared the average retail rate of each
jurisdictional utility to the average retail rate for all
electric utilities in the region. Any electric utility whose
retail average rates exceeded the regional average rate was
afforded a lower level of stranded cost relief than those
utilities whose average rate was at or near the regional average.
This order addresses all outstanding motions for rehearing
or clarification relative to the policies or legal positions
articulated in the Plan except those portions of the Plan or
Legal Analysis that specifically addressed the PSNH Rate
Agreement entered into with the State of New Hampshire as part of
its bankruptcy reorganization. Accordingly, this order affirms,
clarifies and modifies the generic policy statements, supporting
legal analysis and compliance filing requirements announced
previously in the Plan. In addition, this order reaffirms the
ISC orders of Connecticut Valley Electric Company (CVEC), Granite
State Electric Company (GSEC), the New Hampshire Electric
Cooperative, Inc. (NHEC) and the Unitil Companies (Unitil). The
Commission will issue a separate rehearing order addressing
PSNH's ISC charge based on the information presented at the
rehearing and incorporating the final policies and decisions
articulated herein, as well as the response of the New Hampshire
Supreme Court to our Request for Interlocutory Rulings.
Finally, the Commission announces herein the initiation of
utility-specific compliance proceedings and several rulemaking
dockets, and also reports on the status of various activities,
both at the State and regional level, which are related to the
implementation of RSA 374-F.
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2. PROCEDURAL HISTORY
The Commission received 14 timely motions for rehearing or
clarification concerning the Plan and ISC orders. By Order No.
22,548 (April 7, 1997), the Commission suspended and stayed
portions of the Plan and ISC orders pending further evaluation of
the issues raised in these requests. The Commission also granted
requests for further public hearings on one generic policy issue
and several PSNH-specific issues. See, Order No. 22,576 (April
30, 1997). The policy issue concerned whether utilities should
continue to administer ratepayer-subsidized energy efficiency
programs. The PSNH-specific rehearing issues related to its ISC
order; specifically, they related to whether that order (and the
Plan) will cause PSNH to breach certain debt covenants and
whether the Plan violates the 1989 Rate Agreement executed by
PSNH and the State of New Hampshire.
The rehearing proceedings were originally scheduled for May
1997 but were continued on two occasions at the request of a
number of parties, including the State of New Hampshire, who
sought to participate in a confidential mediation process
overseen by the United States District Court of Rhode Island.
See, Order Nos. 22,599 (May 22, 1997) and 22,664 (July 21, 1997).
The Commission conducted a hearing on energy efficiency on
October 9, 1997. The PSNH- specific rehearings began in November
1997; legal memoranda were filed on December 19, 1997. The
Commission also accepted comments on issues concerning transition
service and affiliate transactions as requested by some parties.
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3. DISCUSSION
a. Procedural Matters
The Plan and ISC orders culminated a nine-month generic
investigation which the Commission initiated to fulfill its
statutory responsibilities under RSA 374-F. That law instructed
the Commission to develop a statewide industry restructuring plan
and establish ISC charges for each utility no later than February
28, 1997. RSA 374-F:4, II. Consistent with these dual
objectives, the Commission segmented the docket into two
procedural phases: the first phase allowed parties to comment on
generic policy matters; the second phase was dedicated to setting
utility-specific ISC charges. The Commission employed panel-
based legislative type procedures to address generic policy
questions and separate utility-specific adjudicative proceedings
to set ISC charges in accordance with RSA 541-A:31-36.
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i. Rehearing Requests - Procedural Matters
Each of the electric utilities subject to RSA 374-F,
with the exception of NHEC, assert on rehearing that the
procedures employed by the Commission were inadequate or legally
insufficient. PSNH and CVEC argue that the Commission erred by
not utilizing formal adjudicative procedures to address every
issue raised by RSA 374-F. GSEC asserts that the Commission
should have conducted a formal rulemaking. Unitil claims that
the Commission was required to conduct every part of this docket
through either formal adjudication or rulemaking.
The foregoing entities also assert other miscellaneous
procedural errors. PSNH argues it had inadequate discovery
rights and was improperly foreclosed from presenting testimony,
cross-examining witnesses and presenting rebuttal evidence. PSNH
also claims that one of the Commission's decisional employees
"evidenced an appearance that he has committed to a highly
adversarial position" and that certain unspecified violations of
the statutory standards of conduct set forth in RSA 363:12, III,
IV and VII prejudiced the company. CVEC complains that the
Legislature left too narrow a time frame for the Commission to
process the momentous matters involved in this case, leading to
procedural deficiencies and "pre-ordained results" in the Plan.
Unitil complains that it was improperly denied the opportunity to
discover the legal or statutory basis for the Commission's legal
analysis.
The Office of Consumer Advocate (OCA) argues that the
Commission allowed PSNH more procedural protections than other
interested parties, including a greater opportunity to submit
testimony on the Rate Agreement.
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ii. Commission Conclusions - Procedural Matters
We have addressed previously most of the procedural
issues raised in the aforementioned rehearing requests. By Order
No. 22,244 (July 22, 1996), we rejected PSNH's contention that it
was entitled to a formal adjudicative process to resolve "each
and every issue" in this proceeding. In that order, we
announced our intention to use adjudicative procedures to
establish utility-specific ISC charges and panel-based,
legislative style procedures to explore generic policy issues.
We affirm those decisions and reiterate our position that we were
not required to employ formal adjudicative procedures, or a
formal rulemaking, before issuing generic policy statements in
the Plan. In addition, we reject any new claims advanced on
rehearing that the procedures afforded throughout this docket
were legally inadequate. We were, and are, satisfied that all
parties were given an adequate opportunity to build a
comprehensive record upon which the Commission could rely to
develop these generic policy statements. The processes employed
throughout this docket went beyond what was constitutionally
required or contemplated by the Legislature when it enacted RSA
374-F. In affirming our prior decisions on these matters, we
have nonetheless decided, sua sponte, to clarify both the nature
and intended purposes of the Plan in the following section.
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b. Nature of the Plan
The Legislature instructed the Commission to "undertake a
generic proceeding to develop a statewide industry restructuring
plan...[and] after public hearings, issue a final order no later
than February 28, 1997." RSA 374-F:4, II. Since the Legislature
did not define the term "statewide plan", it afforded the
Commission wide latitude. As stated in the Introduction, the
Plan was intended to serve three primary functions: to articulate
the Commission's general restructuring blueprint; to issue
generic policy statements; and to establish utility compliance
filing requirements consistent with those policy pronouncements.
In essence, the Plan simply announced the Commission's blueprint
for implementing RSA 374-F; it did not supplant the underlying
policy directives of RSA 374-F. Nor was it intended to supersede
RSA 374-F. It was instead, the implementation tool for the
legislative mandate upon the State's electric utilities to
provide open access services so that consumers could purchase
electricity from competing suppliers no later than July 1, 1998.
Although the Legislature did not explicitly require it, we
issued, as part of the Plan, generic policy statements. We
recognized the need to implement some of those broad policies
through formal rulemaking proceedings. We recognize further,
however, that some policy objectives could be advanced only
within regional or federal forums.
The Plan, even as modified by this order, therefore, should
not be construed as the Commission's final declaration of its
ongoing responsibility to enforce the mandates of RSA 374-F.
Rather, the Plan provides parties with policy guidance in certain
areas and requires utilities to submit compliance filings
consistent with those policies.
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c. General Policy Considerations
We affirm the fundamental rationale and objectives in the
Plan which require us to develop and implement sound public
policy. The passage of RSA 374-F has not altered the
Commission's fundamental responsibility under RSA 363:17-a to
balance the interests of customers and utilities. It has imposed
upon us the new responsibility of developing and implementing
policies that will encourage a competitive retail market for
electricity services. The Legislature clearly instructed us to
design and implement policies to achieve that particular
objective when it stated the purpose of RSA 374-F this way:
The most compelling reason to restructure the New
Hampshire electric utility industry is to reduce costs
for all consumers of electricity by harnessing the
power of competitive markets.
RSA 374-F:1, I (emphasis added). Thus, although we continue to
recognize the competing interests of consumers and utility
shareholders, we must do so within the framework of an overall
policy to promote a competitive market for retail electric
services.
We firmly believe that the legislative mandate to implement
pro-competitive policies will yield long-term benefits for
consumers and the State. Although substantial opportunities
exist for consumers to enjoy short-term gains, we believe that it
is appropriate to develop sound, long term policy while achieving
near term rate relief consistent with RSA 374-F.
We recognize that the desire to avoid litigation may lead
some parties to enter into "settlement agreements" by
collectively proposing changes to the policies announced in the
Plan as modified herein. Generally, the Commission encourages
parties to seek consensual resolutions to contested issues. We
do not intend to foreclose those opportunities in this or related
proceedings. Parties to any such proposal, however, should be
mindful that the Commission cannot abdicate its statutory
responsibilities which include laying the groundwork for an
effective competitive market for retail generation and ancillary
energy services and achieving near term rate relief. In order to
approve any settlement proposal, we must be satisfied that it
substantially adheres to the Legislature's policies as
articulated in RSA 374-F. In particular, we will carefully
scrutinize any proposal to ensure that it does not compromise the
substantial and long-term benefits which will accrue to the State
through sound industry restructuring policies in exchange for
modest short-term gains or an agreement that minimally complies
with the language but not the long-term purposes of RSA 374-F.
With or without settlement agreements, we will do everything
within our delegated authority to ensure that utilities comply
with the requirements of RSA 374-F by July 1, 1998.
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d. Open Access Requirements
RSA 374-F authorizes and directs the Commission to require
New Hampshire's electric utilities to provide retail customers
with unbundled, non-discriminatory transmission and distribution
services no later than July 1, 1998. See, RSA 374-F:4, I. We
affirm our commitment to enforce unbundled, non-discriminatory
transmission and distribution services, although, as discussed
below, we have vacated our prior directive concerning the filing
of retail transmission tariffs. Accordingly, we hereby direct
each jurisdictional electric utility to file proposed
distribution tariffs with rates, terms and conditions that are
consistent with RSA 374-F and our discussion below. As noted
above, the ISC portion of PSNH's proposed tariffs will be
established in a separate order. The Commission will review and,
if necessary, require modification of these tariffs within the
compliance proceedings required by RSA 374-F:4, III. Unless the
Commission orders otherwise, these tariffs shall be effective on
or after July 1, 1998.
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e. Rate Unbundling
Requirement
In the Plan, the Commission directed all jurisdictional
utilities to unbundle their 1996 retail revenue requirements into
the three functional categories of generation, transmission and
distribution. The Commission directed utilities to further
separate distribution revenue requirements into distribution,
metering, billing, customer services and conservation and load
management (C&LM) functions. Pursuant to the Plan, utilities are
required to distinguish between transmission and distribution
revenue requirements in accordance with the FERC's seven factor
test. The Commission also directed utilities to develop
transmission and distribution (T&D) revenue requirements
consistent with the following principles:
T&D rates must exclude all generation-related operation and
maintenance expenses;
T&D rates must exclude all costs associated with wholesale
and retail marketing activities; and
T&D rates must reflect appropriate allocations of
administrative and general expenses.
As part of utility compliance filing requirements, we also
directed utilities to submit a cost-of-service study which
unbundles 1996 test year revenue requirements based on the
foregoing criteria.
No rehearing requests were filed relative to these
requirements. We will modify the Plan, however, to the extent
that it addressed transmission rates and tariffs. As explained
in §III, J of this Order, we will no longer require electric
utilities to file transmission tariffs and will limit our
regulation to distribution rates and tariff terms. Accordingly,
we herein affirm our directive that utilities submit, as part of
their updated compliance filings, 1996 cost-of-service studies
which allocate 1996 test year revenue requirements to each rate
class using the cost allocation techniques underlying existing
bundled rates. The development of transmission rates will be
subject to FERC's jurisdiction.
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f. Scope of
Unbundled Services
In the Plan, the Commission stated that although it would
require utilities to fully unbundle retail rates for all customer
classes, it would unbundle services on a more limited basis
during the transition to a competitive retail market. The
Commission acknowledged that some parties favor unbundling and
opening to competition all identifiable services that no longer
exhibit monopoly characteristics; however, we decided that it was
more appropriate to require an achievable level of unbundling at
the outset of competition and that a more comprehensive
separation of competitive services should be deferred to a later
date. The Plan requires utilities to unbundle only generation
and energy billing services for all customers at the onset of
competition but requires further unbundling (specifically
metering services) for large customers, which we define as any
customer whose maximum demand exceeds 100 kW in any three
successive months. The Commission established a working group to
further explore the technical issues associated with implementing
this metering unbundling policy decision.
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i. Rehearing and Clarification Requests - Unbundled
Services
Several parties requested clarification relative to the
Commission's policy requiring unbundled metering and billing
services. CVEC states that, in light of the Commission's
decision to unbundle both metering and billing services for all
customers over 100 kW "[p]resumably...the meter previously
supplied by CVEC would have to be removed, and CVEC would no
longer have any responsibility to provide meters to these large
customers." In addition, CVEC assumes that customers will be
responsible for any undepreciated meter investment (and billing
service systems) that becomes stranded as a result of the
Commission's policy.
GSEC argues that the Commission's metering policies
raise many new questions. For example, GSEC points to the
Commission's requirement that all customers whose maximum demands
exceed 100 kW shall have hourly metering (Plan at 22). Such a
requirement, according to GSEC, leaves unanswered issues
surrounding the ownership of metering equipment, responsibility
for meter accuracy and testing, coordination of information flow
among competitive suppliers, Independent System Operator (ISO) -
New England, distribution companies and customers, loss
allocations, metering services for default customers, stranded
costs associated with metering equipment, and the right of
distribution companies to meter for their own services and other
unspecified concerns. GSEC suggests that many of these issues
cannot be resolved before the legislatively imposed retail access
date and GSEC, therefore, asks that the Commission establish a
separate schedule for unbundling metering and related services.
According to PSNH, the Commission's policy on metering
exceeds its statutory authority by precluding PSNH from obtaining
its own data for delivery system usage, thus denying the
distribution company the right to perform essential services for
these customers. PSNH also asserts that the Plan fails to
acknowledge that estimated hourly loads are much less accurate
than actual hourly load meter readings. According to PSNH, the
Plan "misconstrues" the study conducted by GSEC.
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ii. Commission Conclusions - Unbundled Services
(1) Metering and Billing
Throughout this order, a large customer will be defined as
one whose maximum monthly demand exceeds 100kW whereas a small
customer is one whose maximum monthly demand is less than or
equal to 100kW. The following policies will be reviewed one
year after their implementation which we expect will be July 1,
1998 or soon thereafter. The primary focus of the Commission's
review will be to determine: (a) whether distribution companies
should remain obligated to provide metering services to large
customers who choose not to obtain those services from
competitive (non-utility) providers, and (b) whether load
estimation is an adequate alternative to measured data for
customers whose metering equipment does not meet the standard
described below. Before fully explaining our decisions in this
area, we provide a brief summary of our conclusions in the
following two paragraphs.
We affirm our decision to allow competitive providers to
offer energy billing services to all customers effective on the
retail competition date. Competitive providers may also provide
meters and metering services to large customers who choose that
option. However, competitive metering will not begin before
appropriate metering standards have been adopted through
rulemaking. By authorizing the competitive provision of meters
and metering services for large customers, we are encouraging the
development of a competitive market for ancillary services,
starting with the most sophisticated, energy intensive customers.
We also affirm our decision to require distribution
companies to provide meters and metering services to small
customers until we see evidence that those services can be better
provided by the competitive market. Although we do not believe
it would be practical to allow all customers to purchase meters
and metering services competitively at the time of retail
competition, we will consider proposals for limited pilot
programs designed for small customers. Phasing in the
competitive provision of metering products and services will
provide for a more orderly transition to retail competition and
to allow small customers an opportunity to learn more about these
options.
PSNH argues that RSA 374-F does not authorize the
Commission to unbundle metering and billing services for any
customer. We disagree. RSA 374-F:1, I states, in pertinent
part, that "[i]ncreased customer choice and the development of
competitive markets for wholesale and retail electricity services
are key elements in a restructured industry that will require
unbundling of prices and services...." and at §3, III states
that "services and rates should be unbundled to provide customers
clear price information on the cost components of generation,
transmission, distribution, and any other ancillary charges."
Additionally, §3, IV requires the Commission to "monitor
companies providing transmission or distribution services and
take necessary measures to ensure that no supplier has an unfair
advantage in offering and pricing such services." We conclude
that the Legislature authorized us to unbundling ancillary
services, including metering and billing, recognizing such
unbundling to be a critical step in the development of a
competitive market for energy services.
In the Plan, we required that metering equipment for
large customers be capable of recording hourly loads and being
read remotely each day in order to reduce the error associated
with the hourly load estimation process. This new standard would
have taken effect on the retail competition date. After further
consideration, we have decided that until we have completed our
review we will leave open the date by which metering equipment
used by large customers must comply with the new standard. Prior
to this review, distribution companies must estimate the hourly
loads of large customers who choose not to purchase metering
products and services competitively and whose existing metering
equipment does not meet the new standard. These changes will
provide for a more orderly transition to a competitive market for
metering products and services and minimize the need for
additional metering investments by distribution companies.
If a customer changes from one competitive energy
supplier to another, we require the existing meter to be left in
place for 60 days or until another meter is installed by the new
competitive supplier. A replacement meter that meets the above
new standard must be installed by the end of the 60 day grace
period unless the old and new suppliers can reach a mutually
acceptable solution. These requirements do not apply to large
customers who, prior to our review, continue to use their
existing metering equipment.
We clarify that meter testing will remain the sole
responsibility of distribution companies and that the connection
of metering equipment at primary voltage levels must be performed
by qualified individuals. We also require distribution companies
to install, when requested, customized meters and/or ancillary
metering devices of competitive providers in a timely and cost
effective manner. Distribution companies will be compensated for
the reasonable costs of providing such services, pursuant to a
Commission approved tariff.
With respect to billing, we clarify that distribution
companies will retain the responsibility to bill all customers
for distribution services. Competitive suppliers, or their
designated agent(s), will assume the responsibility for billing
customers for the energy services they provide. However, for the
convenience of the customers, we will require distribution
companies to offer competitive suppliers the option of including
their unbundled energy charges on a single consolidated bill,
prepared by the distribution company. Again, the distribution
company would be compensated for this billing service pursuant to
a Commission approved tariff.
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(2) Advanced Metering Networks
Both competitive suppliers and distribution company
affiliates may install advanced metering networks employing
automated meter reading technology. An advanced metering network
consists of two or more meters that communicate with a remote
station utilizing wireless or telephone based technologies.
Meters used in an advanced metering network must be able, at a
minimum, to record hourly data and be read remotely.
Distribution companies seeking to install advanced
metering networks must obtain prior Commission approval. In
reviewing any such application, we will evaluate the potential
for stranded metering investments and anti-competitive effects.
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(3) Cost Recovery Issues
We clarify that metering costs, appropriately allocated
for the relevant classes including large customers who choose not
to acquire metering products or services competitively, will be
recovered via unbundled distribution charges. We reiterate that
distribution companies must undertake all reasonable efforts to
mitigate fixed costs not recovered as a result of customers
switching to competitive providers. Distribution companies may
recover the non-mitigatable portion of those costs through the
annual reconciliation of stranded costs and revenues for the
large customer rate classes.
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(4) Acceptance and Installation Standards
To ensure accurate calibration, appropriate
installation and reliable operation, we will require the
development of acceptance and installation standards for all
metering equipment. We ask the metering working group to develop
appropriate standards, which we will consider in a rulemaking.
Those standards must accommodate new technologies. All
competitive providers that intend to install their own custom
meters or ancillary metering devices must first have the
equipment acceptance-tested by the relevant distribution company.
As we noted above, no competitive metering will be allowed for
any customer until the Commission's administrative rules on
metering have been enacted. All metering equipment must comply
with Commission rules.
Return to TOC
g. Vertical Market Power
In the Plan, we found abundant evidence that incumbent
electric utilities possess the ability to exercise vertical
market power and could disadvantage unaffiliated suppliers by
using revenues from regulated functions to cross-subsidize
unregulated functions and by offering affiliates access to
preferential pricing arrangements or customer information. We
concluded that divestiture was the best safeguard against such
conduct. Specifically, we observed:
The shared ownership and control of generation,
transmission and distribution assets provides both the
opportunity and the incentive for management of
regulated companies to favor competitive affiliated
suppliers. The implementation of affiliate transaction
rules insufficiently restricts the incentive to
exercise market power. We believe the corporate ties
between regulated and competitive functions must be
severed in order to eliminate this incentive. In our
view, the only way to sever these corporate ties is
through divestiture. We define divestiture to mean
that an existing utility may no longer provide
competitive and non-competitive services.
To implement this policy, we decided to limit future
electric distribution utility franchise rights. We required any
incumbent electric utility that sought to retain its regulated
distribution functions to submit a plan under which it would
divest its generation and aggregation/marketing functions by the
end of a two-year transition period. We stated, however, that
during the two-year transition, we would allow an affiliate of a
distribution company to offer competitive products and services
provided that the utility satisfactorily demonstrated that it had
implemented sufficient safeguards to prevent anti-competitive
behavior.
Return to TOC
i. Rehearing Requests - Vertical Market Power
On rehearing, each jurisdictional electric utility objects
to the Commission's policy statements concerning the ability of
utility-affiliates to compete for retail customers within their
respective service territories. Most claim that RSA 374-F did
not delegate authority to the Commission to implement such a
prohibition and that in any case, such a policy would be
constitutionally invalid. According to these utilities, the
Commerce Clause of the United States Constitution precludes the
Commission from prohibiting utilities' affiliates from competing
for retail customers within their service territories.
NHEC objects to any order requiring NHEC to divest its
generation and "aggregation/marketing functions" because such
action: (a) may deny NHEC the ability to mitigate its costs
associated with its ownership interest in Seabrook and Maine
Yankee; (b) is inconsistent with previous Commission conclusions
relative to NHEC's ability to provide aggregation services for
its members; and (c) is unlawful and unreasonable given the
nature of NHEC's specific purchase power contracts.
CVEC contends that its parent, Central Vermont Public
Service Company (CVPS), is a Vermont public utility which is not
subject to the Commission's jurisdiction. CVEC states that both
it and CVPS have "expressed a willingness...to minimize the risk
of anti-competitive conduct" through codes of conduct and
affiliate transaction rules.
GSEC argues that the Commission lacks the statutory
authority to prohibit a GSEC affiliate from providing competitive
services within GSEC's service territory. Moreover, GSEC
contends that, even if such authority existed, such a prohibition
"runs counter to the statutory goal of creating a robust
competitive market and does not serve the public interest."
GSEC asserts that the "public interest" standard in RSA 374:26
does not provide the Commission with authority to withdraw a
utility's ability to operate in an otherwise lawful manner in the
state. GSEC also argues that such a policy could stifle
competition by reducing the number of competitive suppliers and
would directly reduce the market value of a distribution company.
The Governor's Office of Energy and Community Services (ECS)
states that, in order to "maximize competition" as a means to
lower costs, utility-affiliates should be permitted to compete
for retail customers within their affiliate's service territory.
According to ECS, the Commission should implement a code of
conduct and then continue to monitor vertical and horizontal
market power issues.
Return to TOC
ii. Commission Conclusions - Vertical Market Power
We continue to believe that divestiture (i.e., separate
ownership of generation from transmission and distribution) is
the most effective way to eliminate vertical market power;
however, we will vacate our decision to prohibit retail marketing
affiliates of an electric distribution utility from offering
competitive services to customers within the franchise service
territory of the distribution utility. We will permit retail
marketing affiliates to compete for retail customers in their
distribution utility's franchise territory, but only after we
approve an appropriate code of conduct to protect against anti-
competitive behavior. We reiterate, however, that distribution
utilities may no longer offer generation-related services to
their customers and we will require corporate unbundling
consistent with our express authority to do so. See, RSA 374-
F:4, VIII. In addition, our decision on this issue applies with
equal force to NHEC, the State's only member-owned electric
utility. We believe that NHEC should be subject to the same
corporate unbundling and code of conduct requirements established
for New Hampshire's other utilities.
We grant this relief on rehearing primarily for practical
purposes. We have decided to defer any ultimate public good
determination on this issue until we are better able to assess
the efficacy of the protections proposed by various parties. We
remain very concerned that, absent divestiture and the preceding
prohibition against retail marketing affiliates of electric
distribution utilities, affiliates may gain an unfair advantage
over other market participants. Consequently, we will require
utilities and their affiliates to operate in strict accordance
with the code of conduct that the Commission will establish in a
generic rulemaking proceeding. In addition, retail affiliates
will be subject to Commission oversight and information
disclosure requirements which will be addressed in this
rulemaking docket. Furthermore, such affiliates must comply with
the rules we adopt in the supplier registration rulemaking. We
will monitor the efficacy of these protections closely to
determine whether vertical market power abuses occur; if they
do, we will take appropriate action and implement additional
protections.
Although we have decided to modify the Plan in the foregoing
manner, we nonetheless affirm our authority to place conditions
on future electric distribution utility franchise rights to
accommodate the retail access policies of RSA 374-F. See, Plan
at 28. We do not accept the argument that we can only limit the
scope of services that a utility may offer after a finding of
inadequate service pursuant to RSA 374:28. Fundamental to our
regulation of a distribution utility is a determination of the
type and quality of services provided. Such a determination will
change over time with advances in technology, changes in customer
needs and the development of competitive markets for energy
services. The enabling legislation we are required to implement
expressly authorizes the Commission to require "that distribution
and electricity supply services be provided by separate
affiliates." RSA 374-F:4, VIII.
In addition to the foregoing express authority under RSA
374-F, the Commission has been delegated incidental authority to
take actions necessary to implement the policies of RSA 374-F.
See, RSA 374-F:4, VIII ("The Commission is authorized to order
such charges and other service provisions and to take such other
actions that are necessary to implement restructuring..."). Even
before the enactment of RSA 374-F, the Commission had the
authority and duty to prescribe terms and conditions on franchise
rights whenever it would serve the public good. RSA 374:26.
That authority has a special application to these circumstances
because our delegated mandate is to promote competition not to
perpetuate monopolies. As the New Hampshire Supreme Court
stated:
..[L]egislative grants of authority to the PUC should
be interpreted in a manner consistent with the State's
constitutional directive favoring free enterprise.
Limitations on the right of the people to "free and
fair" competition"...must be construed narrowly, with
all doubts resolved against the establishment or
perpetuation of monopolies. RSA 374:26 thus should not
be interpreted as creating monopolies capable of
outliving their usefulness.
Appeal of PSNH, 141 N.H. 13, 19 (1996) (emphasis added) (internal
citation omitted).
In this case, we have identified specific circumstances
where electric utilities may exploit their privileged status to
inhibit the development of a competitive retail electricity
market. We will implement special protections to mitigate these
anti-competitive practices. Should we determine these special
protections are insufficient, we will impose additional pro-competitive measures.
In light of the foregoing, we will initiate a rulemaking to
establish affiliate transaction rules which will govern the
conduct and relationships between regulated utilities and their
unregulated affiliates. Several other jurisdictions, notably
Massachusetts and California, have issued rules governing
affiliate transactions. As we considered affiliate transaction
rules, we saw value in using the rules adopted by one of those
jurisdictions as a starting point for the rulemaking proceeding
we would initiate on affiliate transactions. We have chosen to
use the rules adopted by California as the initial document for
the rulemaking docket we intend to open, however, we would
caution parties that our decision to do should in no way be
interpreted to mean that we have prejudged this issue. Rather
it reflects our recognition of the July 1, 1998 implementation
date mandated by RSA 374-F and will help expedite the rulemaking
proceeding. Parties interested in participating in the affiliate
transaction rulemaking docket should contact our Executive
Director. Copies of these affiliate transaction rules will be
posted on the Commission's web page.
Return to TOC
h. Trade Name Prohibition
In the Plan, we prohibited utility-affiliates from marketing
to customers by using a trade name that resembles that of the
distribution company. On rehearing, several utilities
challenge that policy based on their assertion that it violates
the commercial free speech protections of the First and
Fourteenth Amendments of the United States Constitution.
Without addressing the merits of those constitutional claims, or
in any way agreeing that the claims have merit, we have decided
to vacate the blanket prohibition against the use of such trade
names. We are persuaded that until we have more experience
with the marketing practices of generation suppliers, including
those who are affiliated with distribution companies, we should
not, at the outset of competition, act to bar the particular
marketing practice of name usage. Notwithstanding the foregoing,
competitive suppliers will nonetheless be required to comply with
applicable registration, disclosure and consumer protection
rules, some of which may have an impact on the manner in which
suppliers advertise. In taking this action, we have simply
decided to impose a less rigid approach to address the consumer
protection and market power concerns which we expressed in the
Plan. However, we will require a competitive supplier who
utilizes such a trade name to disclose its affiliation(s) with
regulated utilities and provide the additional disclosures that
may be required by our affiliate transaction rules.
Return to TOC
i. Regulation of
Distribution Services
In the Plan, the Commission noted that it would continue to
regulate electric distribution utilities whose primary duty would
be to provide retail customers with open access distribution
services. In addition, we required electric distribution
utilities to maintain their obligation to provide metering,
billing and customer services for all customers whose peak loads
do not exceed 100 kW. The Plan also provides that for those
customers whose peak load exceeds 100 kW, metering, energy
billing and customer services will be provided competitively. As
noted above, we have modified this to some degree in this order.
The Plan also provides that distribution services will be
regulated exclusively by the Commission and that rates for retail
distribution services will be set in accordance with traditional
cost of service principles. We explained that some form of
performance based rate-making may be appropriate for distribution
companies in the future; however, before implementing such
methodology, the Commission must further examine the costs of
providing distribution services. For rate-setting purposes, we
adopted FERC's seven-factor technical test to demarcate, but not
delineate, distribution and transmission facilities. As part
of compliance filing requirements, we directed utilities to
determine the revenue requirement for individual rate classes
using the allocation methodology underlying retail rates
currently in effect. We further directed utilities to include
in their compliance filings a breakdown of distribution costs
into specific cost categories, such as customer service,
operations and maintenance, capital replacements/additions and
metering and billing. We invited utilities to propose
alternative rate design methodologies as part of their compliance
filings, although we advised that any such filing should include
an analysis of the rate impact(s) of such alternatives.
Finally, we observed that the return on equity (ROE)
component of the distribution company's revenue requirement
should reflect its reduced risk.
Return to TOC
i. Rehearing Requests - Regulation of Distribution
Services
Several entities argue that the Commission improperly
made generic findings regarding the ROE component of regulated
distribution rates. According to CVEC, distribution companies
face the risk of entry by competitors and uncertainty regarding
cost recovery for newly ordered competitive functions. CVEC
argues that its cost of capital should reflect these risks.
PSNH contends that the Commission must set the
appropriate level of return on equity in utility-specific rate
proceedings based on financial market requirements.
CVEC also asks for clarification on whether an
investment made today will be recoverable in the future if that
part of its operations in which the investment is made becomes
competitive in the future.
Return to TOC
ii. Commission Conclusions - Regulation of
Distribution Services
We reaffirm the policy announced in the Plan to set the
rates, terms and conditions for distribution services within the
compliance proceedings for each utility. We clarify that the ROE
component of distribution rates will be set based on traditional
rate making principles. For compliance filing purposes, we
direct each utility to use the last Commission-approved ROE for
an electric utility, 10.2% however, we will adjust that
component of distribution rates based on the outcome of
individual rate cases. See Order No. 22,537 in DR 96-170.
We cannot provide CVEC with its requested clarification
concerning whether investments made to provide distribution
services will be fully recovered through regulated rates. That
issue will be addressed in a future distribution company rate
case applying appropriate ratemaking principles.
Return to TOC
j. Regulation
of Retail Transmission Services
In the Plan, the Commission announced a general policy
decision to defer to the jurisdictional paradigm established by
FERC in Orders Nos. 888 and 888-A with respect to the provision
of unbundled retail transmission services. However, the
Commission also directed transmission-owning utilities to develop
and file with this Commission special retail tariffs for New
Hampshire customers before filing such tariffs with FERC. In
establishing this filing requirement, the Commission determined
that it was necessary to shape the terms and conditions of retail
transmission because many parts of FERC's pro forma tariff are
inappropriate for retail transactions. The Commission recognized
the risk that inconsistent retail transmission policies could be
developed by the different state regulatory authorities in the
New England region and that FERC would be the appropriate final
authority to establish the rates, terms and conditions of retail
transmission. Under this approach, the Commission assumed FERC's
ultimate authority to regulate retail transmission service but
determined that the Commission had the authority to review and,
if necessary, require modification to proposed retail
transmission tariffs before requiring the filing of such tariffs
at the FERC. The Commission acknowledged that any modifications
must conform with the policies and principles enunciated in the
FERC's Open Access Rule.
Return to TOC
i. Rehearing Requests - Retail Transmission Services
On rehearing , PSNH, Unitil, GSEC and CVEC challenged
this aspect of the Plan. Although each of these parties casts
its argument in a slightly different fashion, all contend that
the Federal Power Act (FPA) preempts the Commission from
requiring utilities to make retail transmission filings here or
at FERC.
In addition to the foregoing, GSEC argues that it is
under no obligation to provide retail transmission services.
GSEC states that it owns no transmission facilities, that such
facilities are owned by GSEC's affiliate, New England Power
Company (NEP), and that NEP has filed open access tariffs
pursuant to the directives of FERC's Order No. 888. GSEC states
that NEP's open access tariffs will be made available to its
retail customers only if a voluntary restructuring plan is
successfully developed between NEP and GSEC.
Cabletron Systems Inc. (Cabletron) and the Retail
Merchants Association (RMA) jointly filed a motion urging the
Commission to consider an alternative approach to "assure that
there can be no colorable challenge based upon federal preemption
that might delay implementation of the retail access program."
Cabletron/RMA Motion at 9.
Return to TOC
ii. Commission Conclusions - Retail Transmission
Services
In the Plan, we assumed FERC's ultimate jurisdiction
over retail transmission services but asserted that we possessed
the legal authority to review and require modification to
proposed retail transmission tariffs as a condition to future
grants of authority to operate a monopoly electric distribution
service in this State. We explained that the Commission has the
statutory authority to define utility franchise rights through
the imposition of such conditions, stating:
...[T]he Commission has the authority to establish the
conditions under which a utility provides service in
this state. The right to own and operate transmission
facilities in New Hampshire is obtained only through
the permission of the Commission. The Commission can
and will condition that continued permission on the
transmission owner's willingness to make a filing at
FERC for retail transmission service consistent with
the terms and conditions established by the
Commission.
We continue to believe that the Commission possesses broad
statutory authority to impose new conditions on electric utility
franchise rights in order to promote competition or mitigate
anti-competitive practices in that industry. Even before the
enactment of RSA 374-F, the Commission had a statutory duty to
institute such policies whenever it would serve the public good.
See, Appeal of Public Service Company of New Hampshire, 141 N.H.
13 (1996). In short, we affirm our belief that electric
utilities in this State possess no vested right to operate a
monopoly franchise free from the imposition of new standards or
conditions which are specifically designed to promote free and
fair competition in the retail market for electric services.
On the other hand, this particular compliance filing
requirement may unnecessarily create confusion over the
respective jurisdictional roles of the Commission and FERC. In
previous orders, we expressed an intent to work within the
jurisdictional paradigm established by FERC in its Open Access
Rule. We remain encouraged by FERC's stated desire for a
cooperative regulatory regime which accommodates both state and
federal policy concerns. During our retail competition pilot
program we identified several provisions of the FERC's pro forma
tariff that were inconsistent with retail transactions, and FERC
promptly granted a waiver of those provisions. In Order 888-A,
FERC reiterated its willingness to modify the pro forma tariff to
accommodate state retail access initiatives. Although the
procedural path to seek such modifications is not entirely clear,
FERC has indicated that it intends to address such state requests
on a case-by-case basis. Id.
After weighing the competing considerations with
respect to this issue, we have decided to modify the policy
decision announced in the Plan to the extent that it requires
utilities to develop specially tailored retail transmission
tariffs before making such filings at FERC. Instead, filings by
utilities (or their affiliates) will now be voluntary. We will
not require utilities or their affiliates to submit for our
review and approval new tariffs specifically designed for retail
transmission in New Hampshire. However, we strongly encourage
jurisdictional utilities to cooperate with the Commission and
other interested stakeholders in developing appropriate retail
transmission tariffs at the state level. In the absence of
cooperation, we will take such action as is necessary to ensure
that retail competition is not blocked by utilities denying
customers access to appropriate transmission services.
Finally, we announce our intention to schedule
technical sessions to allow interested parties to discuss the
applicability of the FERC's pro forma tariff to retail
transactions and the possible modifications thereto that may be
appropriate to accommodate New Hampshire retail customers.
Participation in these technical sessions is voluntary, although
parties should be on notice that the results of these sessions
may form the basis of generic waiver requests by the Commission
at FERC. Utilities willing to cooperate with the Commission and
its Staff in developing retail transmission tariffs tailored for
New Hampshire customers should file their proposed tariff with
the Commission as part of the updated compliance filing
requirements. In the event that a utility declines to file such
a tariff on a voluntary basis, it should so inform the Commission
in its updated compliance filing.
Return to TOC
k. Interim
Stranded Cost Recovery
The Commission has been authorized and directed to set an
ISC charge for each utility as part of a "generic restructuring
order...[and] without a formal rate case proceeding." RSA 374-F:4, II. The stated purpose of this legislative directive is "to
facilitate the rapid transition to full competition. " RSA 374-
F:4, VI(a). ISC charges are to remain in effect for a two-year
period following the implementation of utility compliance
filings. Id. By statute, ISC charges can establish no legal,
factual or policy precedent concerning subsequent requests for
"final" stranded cost recovery. RSA 374-F:4, VI(b). See also
RSA 374-F, V (authorizing "final" recovery only in the context of
a rate case proceeding) .
Each utility's ISC charge must meet the following criteria:
first, it must reflect the Commission's preliminary determination
of an "equitable, appropriate, and balanced measure of stranded
cost recovery"; second, it must "take[ ] into account the near
term rate relief principle"; and third, it must be "substantially
consistent" with the Legislature's interdependent policy
principles. RSA 374-F:4, VI(a). The Commission must make a
public interest finding before putting an ISC charge into effect.
Finally, RSA 374-F:4, VI(b) provides that any utility may seek
adjustment of the ISC charge "at any time based on severe
financial hardship."
The near term rate relief principle provides, in part, as
follows:
The goal of restructuring is to create competitive markets
that are expected to produce lower prices for all customers
than would have been paid under the current regulatory
system. Given New Hampshire's higher than average regional
prices for electricity, utilities, in the near term, should
work to reduce rates for all customers. To the greatest
extent practicable, rates should approach competitive
regional electric rates.
The interdependent principle in RSA 374-F that deals with
stranded cost recovery provides, in part:
In making its [stranded cost] determinations, the
[C]ommission shall balance the interests of ratepayers
and utilities during and after the restructuring
process. Nothing in this section is intended to
provide any greater opportunity for stranded cost
recovery than is available under applicable regulation
or law on the effective date of this chapter.
The Plan adopted a generic "benchmark" rate setting
methodology for determining ISC charges. This approach was
specifically designed to implement the Legislature's directives
concerning the establishment of ISC charges. Briefly, the
approach called for the following steps. First, the Commission
compared the bundled rates for each New Hampshire utility to the
average bundled rate for all New England utilities. Utilities
whose bundled rates were at or below the New England average were
allowed full stranded cost recovery on an interim basis. In the
case of utilities whose bundled rates exceeded the regional
average, we established a bundled rate target at a level which
was actually above the regional average, and it was this rate
target from which the ISC charges were derived. We set the rate
target for high cost utilities at a level above the regional
average to minimize the financial impact on those high-cost
utilities; however, by raising the rate target we also reduced
the possible savings which customers would otherwise realize
during the period the ISC charges were in place.
The ISC orders implemented the regional average approach on
a utility-specific basis. For utilities with rates below the
regional average (GSEC, Unitil), the approach yielded an ISC that
provided 100% stranded cost recovery. For utilities with
rates that exceeded the regional average (PSNH), the approach
yielded an ISC that produced less than 100% recovery. CVEC
and NHEC both presented case-specific circumstances which were
addressed in their ISC orders. In PSNH's case, the Commission
set an ISC charge effectively lowering retail rates to within
108% of the regional average. We explained that such an
outcome was consistent with the applicable statutory standards
and stated as follows:
In setting these [interim stranded cost] charges, we
must be guided by RSA 374-F which requires us to
determine rates which are equitable, appropriate, and
balanced and in the public interest...The Legislature
also stated that restructuring should produce rates
that to the greatest extent practicable approach
competitive regional electric rates. This suggests
that rate differences between New Hampshire utilities
and investor-owned utilities in other New England
states, which puts New Hampshire at a competitive
disadvantage relative to its neighbors, should be a key
consideration in the setting of stranded cost
charges.
We specifically refuted PSNH's claim that all utility investors
should have a reasonable expectation to earn a return on their
investment, irrespective of the retail rates a company charges
and stated as follows:
In New Hampshire, utilities have always faced the risk
that retail competition would be substituted for cost
of service rate regulation. It should be of no
surprise that investors of a utility which has
maintained its rates, hence costs, at or below the
regional average views the risk of competition much
differently than a high cost utility...In light of the
fact that electric utilities in this State have always
faced the prospect of retail competition, it should
come as no surprise that those companies with rates
significantly in excess of regional rates would be the
most vulnerable to competition. In other words, this
Commission has always possessed the legal authority and
duty to allow electric service to be provided through a
competitive market rather than monopoly providers.
See, Appeal of Public Service Co., 141 N.H. 13 (1996).
Those companies with the highest rates should have
reasonably anticipated their relative vulnerability as
compared to companies with rates at or below the
regional average. The regional average approach simply
reflects the level of risk which investors in New
Hampshire's electric utilities should reasonably have
anticipated.
In sum, we concluded that the regional average approach was both
equitable and consistent with the "manifest policy of the
Legislature as articulated in the near term rate relief
principle."
Return to TOC
i. Rehearing Requests - Interim Stranded Costs
(1) ISC Charge Methodology
Several utilities challenge the statutory basis for
using the regional average benchmark to set ISC charges. CVEC
contends that "RSA 374-F...which is in any event of dubious
validity, does not contain any affirmative authority for a
regional rate cap for purposes of limiting stranded cost
recovery." CVEC Motion at 36. PSNH argues that the approach
violates RSA 374-F:1 by reducing costs for consumers of
electricity via an uncompensated taking of private property
rather than by harnessing competitive markets. Unitil argues
that the regional average ISC approach is an overly broad and
vague standard that may result in an arbitrary and capricious
level of stranded cost recovery.
Return to TOC
(2) "Takings" Arguments
Each jurisdictional utility, with the exception of
NHEC, argues on rehearing that the Commission's approach for
implementing the stranded cost policies of RSA 374-F is
inconsistent with their purported rights under the "Takings
Clause" of the United States Constitution and the analogous
protections under the New Hampshire Constitution. These entities
allege similar constitutional violations will occur if they are
compelled to offer retail customers unbundled transmission and
distribution services on the asserted basis that such action will
constitute a non-consensual physical occupation of their private
property.
CVEC alleges that "[t]he Commission's decision and RSA
374-F, as applied to CVEC with respect to stranded costs,
constitute unlawful takings of private property...[as] these
determinations unfairly frustrate, and are utterly inconsistent
with, the reasonable expectations of CVEC, CVPS and investors
." According to CVEC, "the existence of a satisfactory end
result is what precludes further inquiry as to whether an
unlawful taking has occurred...[and] the Commission has no basis
for asserting a satisfactory end result with respect to CVEC, and
further inquiry is thus appropriate."
PSNH alleges that the Plan (and the PSNH ISC order )
"violate the state and federal constitutional provisions
outlawing uncompensated takings of property in that near-term
savings to customers are produced solely by confiscation of the
private property of investors."
Unitil contends that "the Commission's abrupt change in
rate making methodology (retaining original cost' for
distribution and transmission services and moving to fair value'
for generation services), without consideration of providing cost
recovery for utility expenditures...may deprive utilities of
their property without just and reasonable compensation."
Unitil cites as authority for its right to stranded cost recovery
the United States Supreme Court decisions in Duquesne Light Co.,
v. Barasch, 488 U.S. 299, 307 (1989) and Federal Power Comm'n v.
Hope Natural Gas Co., 320 U.S. 591 (1944).
According to GSEC, the Commission erroneously
"consistently rejected the constitutional arguments under the
takings clause of the New Hampshire and United States
constitutions...[ and] [a]s a result...failed to recognize fully
the constitutional implications of its orders in this case."
In contrast to the foregoing claims, several non-utility entities argue that the Commission's analysis should be
clarified by making an express finding that the utilities possess
no constitutional right to receive any stranded cost recovery and
that the sole basis for any such relief is RSA 374-F. According
to Cabletron and RMA, the Commission did not address whether
removal of electricity price restrictions can result in a taking;
specifically, Cabletron and RMA argue as follows:
...the Legislature has mandated the removal of
regulation of the price of generation and the setting
of rates by the marketplace. Where the marketplace,
rather than government action, causes loss of property
value or an inability to recover costs, there can be no
taking.
Cabletron and RMA urge the Commission to clarify the Plan by
explicitly declaring that utilities have no constitutional basis
to complain if the Commission exercises its discretion and grants
a utility less than full stranded cost recovery.
Return to TOC
(3) Federal Power Act/Preemption Claims
Each jurisdictional utility, with the exception of
NHEC, claims on rehearing that the ISC charges established by the
Commission must specifically incorporate anticipated purchase
power costs associated with existing FERC-approved wholesale
power contracts. Several of these entities also suggest that
the Commission must pass through to retail customers the stranded
costs incurred by a wholesale supplier who no longer provides
wholesale service to an electric utility because of load losses
caused by retail access.
GSEC argues that its all-requirements contract with NEP
is subject to FERC's exclusive jurisdiction, "including the full
recognition and recovery of costs associated with industry
restructuring." GSEC argues that absent a voluntary
restructuring, GSEC would be required to pay NEP stranded costs
pursuant to FERC's Order No. 888 as affirmed in Order No. 888-A.
GSEC asks the Commission to (a) fully recognize the preemptive
effect of the [FPA] and Order Nos. 888 and 888-A, (b) withdraw
the directive for GSEC to give notice under its wholesale
contract with NEP, and (c) approve the voluntary and timely
restructuring of the NEP-GSEC wholesale power contract.
CVEC makes similar claims and contends that as long as
its wholesale rate schedule with CVPS remains in effect, the
Commission is prohibited from preventing the retail recovery of
those wholesale costs. According to CVEC, unless FERC authorizes
the termination of its existing rate schedule with CVPS, CVEC
must continue to purchase full electric requirements from CVPS,
and CVEC may not be prevented from recovering these wholesale
costs from its retail customers.
PSNH argues that the Commission's approach will
cause a "trapping" of costs in violation of the "filed rate
doctrine" under the FPA. Unitil makes a similar claim and
alleges that the Commission is prohibited from denying full
recovery of power costs billed to Unitil's distribution companies
through operation of the FERC-approved Unitil System Agreement.
Return to TOC
ii. Commission Conclusions - Interim Stranded Costs
(1) Introductory Comments
As previously noted, the Commission is required to set
ISC charges so as "to facilitate the rapid transition to full
competition." RSA 374-F:4, VI(a). Our restructuring orders thus
far (including this one) address only ISC claims; final stranded
cost recovery issues must await another day. We note that ISC
determinations establish "no legal, factual, or policy precedent
with respect to the final determination of stranded cost
recovery." RSA 374-F:4, VI(b).
The distinction between interim and final stranded cost
determinations guides the Commission's review of the rehearing
requests. Accordingly, this section addresses the rehearing
requests which challenge the "generic" stranded cost policies
used to set Interim stranded cost charges.
The Legislature's ISC policies are designed to achieve
two distinct but related objectives. The Commission must
equitably allocate between utilities and customers the risks and
burdens associated with the transition to retail competition.
The Commission has made a preliminary determination, which is
reflected in the various levels of ISC recovery allowed, that a
greater opportunity for full ISC recovery should exist for
utilities: (1) whose current bundled rates are reasonably close
to the regional average rate and/or (2) who engage in voluntary
restructuring activities, such as generation asset divestiture,
to accommodate the implementation of retail access.
This preliminary determination dovetails with the goal
of achieving near term rate relief in a way that facilitates the
"rapid transition to full competition." RSA 374-F:4, VI(a). The
Commission's preliminary ISC determinations for utilities whose
rates exceed the regional average benchmark show this goal was
addressed. Customers of those utilities are the intended
beneficiaries of the near term rate relief purpose of the law.
We believe that a rapid transition to competition will spur
higher cost utilities to improve efficiencies and to mitigate
stranded costs. Both objectives were met by allowing recovery of
some, but not all of the claimed stranded costs.
We believe that the regional average benchmark approach
is conspicuously well-suited to achieve the Legislature's policy
objectives. Moreover, such an approach is clearly supported by
the United States Supreme Court's decision in Permian Basin Area
Rate Cases, 390 U.S. 747 (1968). For utilities with costs lower
than the benchmark, the use of rates based on the regional
average will permit recovery of 100% of estimated stranded
costs and acknowledge that these utilities have satisfied an
important objective of keeping New Hampshire electric rates
competitive with those throughout New England. For higher-cost
utilities, setting preliminary rates above the benchmark but
below 100% recovery of stranded costs gives them an incentive to
improve their operations so as to achieve competitive pricing.
Although individual utility ISC charges could be set as
part of a "generic restructuring order...[and] without a formal
rate case proceeding," RSA 374-F:4, II, we did examine the
effects of the regional average price benchmark separately on
each utility. Order Nos. 22,509-13. Where the Commission
determined an adjustment was justified, the ISC charges were set
above the regional average benchmark to give partial recognition
to claimed potential hardship. This approach encourages
utilities to mitigate stranded costs, RSA 374-F:3, XII(b) and
(c), and offers relief from claimed hardship of the transition.
As required by RSA 374-F:4, VI(b), where "severe" financial
hardship can be shown, we will not rule out the possibility that
other adjustments may be allowed.
We stand by our finding that the regional average
benchmark serves as a helpful measure in determining the
appropriate balance between utilities and consumers; thus, it
complies with the statutory directive to "balance the interests
of ratepayers and utilities during the restructuring process."
RSA 374-F:3, XII(a).
The regional average benchmark thus represents a sound
generic methodology for establishing ISC charges based on the
various public interest objectives that the Commission must meet
under the statute. As explained in the Plan's legal analysis
(pp. 10-12), use of regional pricing has a sound ratemaking
pedigree, making its use as a benchmark for ISC charges
appropriate. Nonetheless, any generic approach, including the
regional average benchmark here, must have a "safety-valve"
mechanism to avoid unintended consequences in specific cases.
The Commission recognizes the need for a waiver
procedure under which ISC charges for an individual utility could
be based on an asset-by-asset application of the statutory
recovery standards. The statute provides a waiver mechanism
where a utility demonstrates "severe financial hardship" from the
application of general ISC charges. RSA 374-F:4, VI(b).
This waiver mechanism responds to PSNH's request for
rehearing. The Commission has already granted PSNH's request to
rehear its ISC based partly on its contention that the use of the
regional average benchmark will require the write-off of certain
regulatory assets. This contention contrasts with the
Commission's finding that PSNH's combined rate for ISC charges
and transmission and distribution services would yield revenues
sufficient to meet its cash needs and produce a pre-tax return on
equity of 10.88%. In its ISC rehearing request, PSNH raised
further complex issues prompting the Commission to request
interlocutory rulings of law from the Supreme Court. Those
matters will be dealt with in a separate order. For purposes of
this rehearing order, however, the important point is that the
law's waiver procedures are fully operational, and they give us
sufficient discretion to adjust the level or methodology of
setting ISC charges for severe financial hardship. RSA 374-F:4,
VI(b). The availability of this statutory procedure to consider
deviations from general application of the benchmark in
individual cases of severe financial hardship negates any claims
that the benchmark should be abandoned as inequitable.
Application of the benchmark also follows established
rate regulation principles: this Commission has always possessed
the legal authority to allow electric service to be provided
through a competitive market rather than by monopoly providers.
Appeal of Public Service Co., 141 N.H. 13 (1996). In competitive
situations, low cost companies are more likely to recover all of
their costs than are high cost companies. Our orders reflect
that principle, but allow some extra relief to high cost
utilities. Thus, the availability of the "severe financial
hardship" waiver offers the possibility of further relief without
the need to abandon the benchmark altogether.
In summary, given the preliminary and transitory nature of
the statutory mandate for setting ISC charges, the benchmark
offers an administratively efficient and objective measure
against which to balance the interests of consumers and
utilities, as the law requires. The Commission's ISC orders have
already made some adjustments to the benchmark approach for
equitable reasons. In the case of PSNH, its initial ISC order
reflected an adjustment. Upon rehearing, we have identified the
need to change the manner in which its ISC charges are set. We
have decided to fashion a cost-based ISC charge for PSNH which is
designed to avoid the accounting problems identified by PSNH and
others during the rehearing process. Further details concerning
PSNH will be addressed in a separate order.
We conclude that the regional average approach is both
equitable and consistent with the interdependent policies that
the Legislature charged the Commission to consider. Accordingly,
the Commission denies the rehearing requests that seek to
overturn the benchmark adopted to make ISC determinations. In
our view, the approach is fully consistent with the Legislature's
express intent as well as with constitutional requirements. This
approach still leaves room for the opportunity to provide a
"severe financial hardship" waiver where appropriate, as in
PSNH's case.
Return to TOC
(2) "Takings" Claims
The Commission rejects the "physical takings" arguments
advanced by utilities as a general prohibition against
application of the open access requirements of RSA 374-F.
Although incumbent utilities will be obligated to offer retail
customers with open access transmission and distribution
services, they will be compensated for the costs of providing
these services through regulated rates. Utilities will be
entitled to rates for such service consistent with
well-established constitutional principles that provide for the
return of, and return on, property devoted to providing those
services.
Should utilities feel that a particular rate for an
open access service is noncompensatory, we have no doubt that
they will challenge that rate. Until such a concrete challenge
is brought, however, it cannot be assumed, as the rehearing
requests do, that rates for such service will necessarily be
unconstitutional. Accordingly, the Commission denies the
rehearing requests seeking to prohibit the open access provisions
from going into effect on claims that an impermissible taking of
property will occur.
The rehearing requests also contend that the Takings
Clause of the United States Constitution (and the commensurate
New Hampshire Constitutional protections) require the Commission
to set ISC charges based on criteria beyond the stranded cost
recovery principles set forth in RSA 374-F. In essence, these
parties contend that they possess a constitutional right to
receive an ISC charge that will guarantee recovery of 100% of
their claimed stranded costs despite the statutory directive
which requires an "equitable, appropriate and balanced measure of
stranded cost recovery." RSA 374-F:4, VI(b).
These contentions, if correct, would undermine the
validity of RSA 374-F itself. Such contentions face very steep,
if not insurmountable, hurdles given the extremely broad powers
that the Legislature possesses to set laws regarding utility
regulation: "It cannot seriously be contended that the
Constitution prevents state legislatures from giving specific
instructions to the utility commissions. We have never doubted
that state legislatures are competent bodies to set utility
rates." Duquesne Light Co. v. Barasch, 488 U.S. 299, 313 (1989).
In this case, the Legislature has offered very detailed
instructions on factors to be considered, objectives to be
achieved and the weight to be given in making ISC determinations.
RSA 374-F:4, VI. On their face, those instructions do not
violate constitutional standards, but attempt to achieve a
balance among the utility and consumer interests affected by the
transition to full competition.
In addition, the Commission has not found a
constitutional right which overrides the statutory instructions,
as the utilities suggest, so as to require us to allow recovery
of all claimed stranded costs regardless of the risks or burdens
associated with the transition to competition. Neither the
United States nor the New Hampshire Supreme Courts have divined a
constitutional right that protects regulated utilities from the
effects of competition. To the contrary, "it is not the mandate
of the constitution to rejuvenate the value of the investments of
a company whose zenith of opportunity has been eclipsed by the
operation of economic forces." Petition of Public Service Company
of New Hampshire, 130 N.H. 265, 277 (1988) (internal quotation
marks and citation omitted). The Commission thus denies
rehearing of those challenges asserting a constitutional right to
recover all stranded costs in all cases. We affirm our intent to
implement RSA 374-F by allocating, through ISC charges, the risks
and burdens associated with stranded costs in a manner that best
serves the law's several public interest goals.
While there is no constitutional protection against the
risk of competition, RSA 374-F does require that the Commission
make preliminary determinations about stranded cost recovery
based on appropriately balanced, equitable grounds during the
transition period to restructuring. In general, full recovery of
all claimed costs is not guaranteed by rate regulation. See 130
N.H. at 277 ("where the balancing of consumer interests against
those of investors causes rates...insufficient to ensure the
continued financial integrity of the utility,...the utility has
encountered one of the risks that imperil any business
enterprise, namely the risk of financial failure") (citation
omitted).
The Commission's balancing of interests in its ISC
orders does, however, weigh the need for continued financial
integrity in the calculus of how ISC charges should be set. For
those utilities permitted to recover, on an interim basis,
100% of stranded costs, continued financial integrity is not
an issue. In cases where some evidence of financial hardship was
shown, adjustments above the benchmark level were granted.
Finally, the waiver procedure permits further relief where a
utility can show "severe financial hardship" under RSA 374-F:4,
VI(b). Thus, consideration of utilities' need for continued
financial integrity has been accommodated in the Commission's
approach.
It must also be reiterated that the ISC charges are
being set at a time when stranded cost issues remain in a fluid
state. At this early stage in the transition to full
competition, utility claims for stranded cost relief are based on
speculative estimates of market values. For example, it has been
claimed that utilities who choose to divest their generation
facilities will realize revenues that are well below the book
costs of those facilities. However, recent initiatives by
utilities in the region to auction their non-nuclear generation
assets have yielded prices that substantially exceed the book
costs of
those assets. In short, the exact level of stranded costs
cannot be known until such a sale is consummated.
The present uncertainty warrants the two stage approach
to stranded cost recovery found in the law. At this time, the
presence of these unknowns limits the Commission to making
preliminary determinations about interim stranded cost recovery
that will have no legal, factual or policy precedent as to how
the Commission can, should or will deal with final stranded cost
questions. Again, in this situation, the law establishes interim
objectives of near-term rate relief, improving New Hampshire's
competitive price position in the region, and easing the
transition to full competition, but not of fully resolving all
stranded cost issues.
Until utilities have complied with the restructuring
mandates, the exact scope of the stranded cost claims (or if
there will be any claims) will not be known. At that time, with
a more fully developed picture than is available now, the
Commission can address those claims consistent with the statutory
objectives for making a final determination of stranded cost
recovery. Consequently, the Commission denies those requests for
rehearing that rest on speculative assumptions about what
stranded costs might result from restructuring as premature.
We turn next to Cabletron/RMA's request for
clarifications. First, these entities ask the Commission to make
an explicit finding that New Hampshire's electric utilities have
no constitutional right to any stranded cost recovery once price
regulation for generation services is removed. Second, they urge
the Commission to articulate a generic rationale for stranded
cost recovery based, not on constitutional principles applicable
to ratemaking, but on the State Constitution and RSA 374-F.
As noted above, our policies regarding ISC recovery
derive fundamentally from the policy objectives embodied in RSA
374-F, which require a balancing of ratepayer and utility
interest in setting ISC charges that are equitable, appropriate
and in the public interest. RSA 374-F:3, XII(a). The Commission
interprets these provisions as requiring consideration of the
financial impact of our ISC determinations on utilities,
irrespective of whether such consideration is required by the
United States or New Hampshire Constitutions. Thus, it is
unnecessary to explore what rights utilities might have been able
to command in the absence of such statutory provisions. On this
basis, we decline to issue a declaratory ruling addressing the
lower constitutional peripheries of utility stranded cost
determinations.
Cabletron/RMA's second request seeks to have the
Commission identify a rationale for allowing interim stranded
costs based on the State Constitution and RSA 374-F, rather than
on federal constitutional principles, which Cabletron/RMA contend
no longer apply once market forces set prices. This request
rests on two faulty assumptions.
First, the request implies that the standards
applicable under the State Constitution or under RSA 374-F are
different from those required by the federal Constitution. We do
not agree: the standards set in RSA 374-F:3, XII(a) and RSA 374-
F:4, VI(a) requiring that stranded cost determinations be
"equitable, appropriate, and balanced" coincide with federal
constitutional requirements. E.g. FPC v. Natural Gas Pipeline
Co., 315 U.S. 575, 582 (1942).
Second, Cabletron/RMA's request, taken to its logical
conclusion, would limit the recovery of fixed generation costs to
amounts which would be received through market prices. To adopt
such a conclusion, the Commission would have to ignore the
explicit statutory language requiring that we "determine rates"
for stranded cost recovery. RSA 374-F:1, III, 374-F:3, XII(a)
and 374-F:4, VI(a). The Commission cannot abdicate express
responsibility assigned to it by the Legislature.
To the extent that Cabletron/RMA's request seeks to
have larger consideration be given to market prices in setting
ISC (or final stranded cost) charges than might be given in
setting rates for a fully regulated utility, the Commission
believes that its regional average price benchmark fulfills that
role as part of the balancing required by the statute. In the
ISC orders, the Commission measured each utility's average
bundled rate against the benchmark to determine whether an
adjustment was appropriate. In the Commission's view, an
adjustment was warranted where a utility's rate exceeded the
benchmark, and thus violated the statutory goals of improving New
Hampshire's competitive position and providing near term rate
relief. Thus, larger consideration has been given to market
forces in setting ISC charges than is the case under traditional
rate regulation.
For these reasons, Cabletron/RMA's second requested
clarification is denied.
Return to TOC
(3) Federal Power Act/Preemption Claims
We reaffirm our decision to address on a case-by-case
basis the recovery of stranded costs associated with existing
wholesale purchased power obligations. Until those
determinations are made, however, we have not prospectively
barred any utility from recovering unavoidable costs associated
with wholesale purchased power obligations. The key is that such
costs be unavoidable, and the statute places "an obligation [on
utilities] to take all reasonable measures to mitigate" such
costs, including renegotiation of existing contracts. RSA 374-
F:3, XII(c). This provision as well as traditional prudence
principles compel utilities to terminate, sell, assign or
renegotiate their existing purchased power contracts to minimize
or, if possible, avoid costs and liabilities associated with
these contracts.
Our decision to defer making final determinations on a
utility-specific basis does not preclude recovery of unavoidable
purchased power expenses. Rather, the Commission has taken the
utility-specific approach on this question to evaluate the
mitigation efforts undertaken by each utility. Because
mitigation efforts will vary on a case-by-case basis, this
approach is the only means for us to comply with the statutory
directive of limiting recovery to unavoidable purchased power
costs that are claimed as stranded.
Return to TOC
iii. Rehearing Requests - Decommissioning Costs
CRR seeks clarification regarding the Commission's
stranded cost policies as they relate to the ability of utilities
to collect nuclear decommissioning charges. Specifically, CRR
urges the Commission to clearly state that "stranded cost
recovery for decommissioning will be for the liability incurred
as of the day of customer choice, not for any increase in that
liability as a result of operation beyond that date."
Return to TOC
iv. Commission Conclusions - Decommissioning Costs
Absent a change in RSA 162-F, the current law on
decommissioning, we continue to believe that the Commission must
provide for the recovery, through a non-bypassable wires charge,
of the estimated costs to safely decommission the Seabrook
nuclear facility at the end of its energy producing life. As to
the request by CRR that such recovery be limited to the costs
incurred as of the retail access date, we note the practical
difficulty of determining which decommissioning cost increases
are the result of operating the facility after the retail access
date and which are due to changes in the decommissioning cost
estimate prior to competition. That complication
notwithstanding, we agree with CRR that on-going costs of nuclear
generation, including incremental increases in the cost to
decommission the facility, could appropriately be considered a
generation-related variable cost. In theory, at least, these
costs could be subject to market forces like any other
generation-related cost. Given the critical health and safety
concerns raised by nuclear decommissioning, however, we are not
prepared to rely solely on the market to collect decommissioning
funds, and we would not advocate a change to RSA 162-F that would
do so.
In the Plan, we called for decommissioning expenses to
be collected as a non-bypassable wires charge, apportioned to
those distribution companies that currently have an ownership
share in Seabrook. Collecting decommissioning expenses according
to a company's ownership share that had been developed in an era
of combined generation, transmission and distribution utilities
raises interesting questions in a restructured environment. Even
at present, before retail competition is in place, we are faced
with one joint owner of Seabrook that has no distribution
function and therefore cannot collect its decommissioning
expenses in a wires charge, which has raised concerns at the
Nuclear Regulatory Commission (NRC) about that joint owner's
assurance of funding its decommissioning obligations. The NRC
concerns and the larger issue of assurance of funding of all
joint owners' decommissioning obligations in a restructured era
have been the subject of lengthy investigation before the Nuclear
Decommissioning Finance Committee, which continues to explore
these issues.
We also are concerned about the impact on stranded
costs if we, or the Legislature, were to adopt a decommissioning
funding mechanism that left collection of decommissioning
expenses to market forces rather than relying on a wires charge.
Our expectation is that the value which could be attained for
nuclear entitlements in a utility asset sale would be greatly
diminished if there were no separate wires charge mechanism to
collect decommissioning expenses. A diminished sale price for
nuclear entitlements means higher stranded costs.
Finally, we must recognize that nuclear decommissioning
is a regional issue, as the Seabrook joint owners are located
throughout New England. This is an issue that must be addressed
on both a state-specific and region-wide basis. We intend to
work with our counterparts within the New England Conference of
Public Utility Commissioners (NECPUC) to seek regional solutions
where appropriate.
We also commit to working with the Legislative
Oversight Committee on Electric Utility Restructuring and other
relevant legislative committees to examine the workings of the
current decommissioning law in the context of a deregulated
generation market. Until there is a change to RSA 162-F, it
would not be responsible to modify the current approach to the
collection of decommissioning costs.
Return to TOC
v. Rehearing Requests - Exit Fees
CRR requests that the Commission reconsider whether
customers who choose to self-generate should pay an exit fee
rather than pay stranded cost charges when and if they actually
utilize back-up services. According to CRR, the Commission's
policy would violate RSA 374-F because it would allow self-
generation customers to bypass" stranded cost charges. In
addition, CRR argues that the ability to avoid stranded cost
charges in this manner will result in cost-shifting between large
customers, who are the most likely customers to self-generate,
and small commercial and residential customers who will have to
assume the stranded cost burden avoided by self-generation
customers. CRR suggests that the Commission impose a demand
charge for self-generation customers except in the case of those
customers who are completely and permanently disconnected from
the grid.
Return to TOC
vi. Commission Conclusions - Exit Fees
We affirm our decision prohibiting the use of exit fees
to recover stranded costs from self-generation customers who
either abandon the grid totally or receive back-up/maintenance
services. CRR apparently agrees with that decision as it relates
to the use of exit fees, but contends that self-generation
customers who retain the right to access the generation market
for back-up power should pay for that right through a demand-
based stranded cost charge. As noted in the Plan, the
opportunity to self-generate has always been a fundamental right
of New Hampshire electric customers. Further, because utilities
have been compensated for that risk through allowed equity
returns, we do not accept the premise that self-generation
actually produces stranded costs. Therefore, CRR's proposal to
recover a greater share of stranded costs from self-generation
customers is in effect an attempt to alter the historic
responsibility for power system costs. We decline to do so. We
also point out that our policies on this issue and on the
recovery of costs stranded as a result of C&LM programs are
consistent, albeit for a different reason. Customers who remain
on the grid but avail themselves of energy efficiency
opportunities (whether funded directly or through contributions
from other customers) are avoiding stranded costs that otherwise
would have been recovered through regulated per kWh rates. In
effect, these customers have chosen to meet a portion of their
energy service needs through "off-grid" means. If we were to
apply CRR's recommendation consistently, customers would no
longer have the incentive to reduce their electric bills by
installing energy efficiency measures. The same argument could
be applied to customers who switch to natural gas or propane for
their heating or manufacturing needs but continue to take grid
service in order to power lighting and appliances.
Return to TOC
vii. Rehearing Requests - QF Costs
The Wood-Fired QFs and Concord Cooperative seek several
clarifications relating to PSNH's on-going obligations to
purchase energy and capacity pursuant to certain rate orders
issued by the Commission. These entities seek clarification on
the following subjects: whether PSNH's current obligations will
change or remain the same after they are "assumed" by the
distribution company serving PSNH's customers; the manner in
which the assumption of PSNH's obligations will take place;
whether a reduction in demand for default service will affect the
obligation of a distribution company to purchase QF supplies;
whether PSNH's obligations to purchase excess energy from the QFs
will remain unchanged; whether PSNH has an on-going obligation to
provide the Wood-Fired QFs back-up power services; and a
clarification with respect to the support relied upon for the
Commission's finding in the Plan that "it is unlikely that the
output by QFs will be sufficient to meet the total load of
default power service." Plan
at 89.
GSHA seeks similar clarifications to those requested by
the Wood-Fired QFs. Specifically, GSHA seeks clarification
relative to a distribution company's on-going QF obligations when
default service demand drops below the aggregate output of QF
power serving the utility.
Return to TOC
viii. Commission Conclusions - QF Costs
We reaffirm our intent to implement RSA 374-F:3, XII(b)
which provides that "utilities should be allowed to recover the
net nonmitigatable stranded costs associated with...power
acquisitions mandated by federal statutes or RSA 362-A." We
decline at this time to address the Wood-Fired QFs' request for
specific findings relative to PSNH's ongoing obligations under
certain long-term rate orders. We reiterate, however, that it is
not our intent to disrupt or impair any legal rights and
obligations which were created as a result of the rate orders,
RSA 362-C or the Public Utility Regulatory Policies Act, 16
U.S.C. 824-a(3) (PURPA). On the other hand, we do not view RSA
374-F as an opportunity for QFs to enhance any such rights.
Utilities have a statutory duty to mitigate all possible
generation stranded costs, including those associated with
existing QF obligations. However, nothing in the Plan or this
Order shall affect the existing rights and obligations of QFs and
utilities.
Return to TOC
l. Special Contracts
In the Plan, the Commission observed that at least fifty
large customers of PSNH or NHEC receive discounted rates through
special contracts that were approved pursuant to RSA 378:18 or
378:18-a. The Commission recognized the potential adverse
effects that special contracts might have on retail competition,
but agreed with PSNH and others who argued that utilities should
continue to honor these contractual commitments after the retail
access date. The Commission did, however, direct utilities with
special contract customers to unbundle their rates into the
primary unbundled service components (i.e., distribution,
transmission, stranded cost and generation). The Plan also
required utilities to deduct from their overall stranded cost
revenue requirement the discount associated with these contracts.
Finally, the Plan directed utilities to include in their
compliance filings a proposal for continuing to supply the energy
needed to meet the requirements of special contract customers.
Return to TOC
i. Rehearing Requests
PSNH contends that the Plan violates RSA 378:18-a, IV
by "imputing to PSNH the difference between regular tariffed rate
and the special contract rate." In addition, PSNH alleges that
the Commission's decision interferes with these special contracts
by requiring PSNH to divest its generating assets and purchased
power contracts.
CVEC alleges that the Commission's special contract
policy is unfair and contrary to the Legislature's intent in RSA
378:18-a, IV.
Return to TOC
ii. Commission Conclusions - Special Contracts
We decline to modify our decision relative to special
contract issues. For the reasons provided in the Plan, we
disagree with PSNH and CVEC that our decision violates RSA
378:18-a, IV. We also disagree with PSNH's argument that our
decision will "interfere" with existing special contracts. There
is no evidence to support PSNH's implicit assumption that the
market price of energy to serve special contract customers will
be greater than the average costs associated with PSNH's current
generation portfolio. Similarly, CVEC has provided no evidence
to support a claim that contributions to fixed costs under the
special contracts will be lower under our policy than currently
exists today.
Return to TOC
m. Default Power Service
In the Plan, we noted that some customers may choose not to
participate in the retail market, and that some competitive
suppliers may not extend offers to certain customers.
Consequently, we developed a conceptual framework which would
require incumbent utilities to provide customers with "default"
generation service by procuring power supplies through a
competitive bidding process and/or spot market purchases. One
possibility, under such an approach will be default service
customers to pay the average price of the winning default power
bids. We specifically found that it would be inconsistent with
our mandate under RSA 374-F to set regulated rates for such
service:
Continuing to offer service to customers at rates fully
regulated by this Commission does not benefit customers
and is inconsistent with RSA 374-F:3, III. It is clear
to us that the load of those customers who either
choose not to participate or who are unable to
participate in the market must be opened up to
competition. If it is not, independent competitive
suppliers, marketers, brokers and aggregators will be
disadvantaged and, consequently, competition will be
inhibited. Our vision of default service is consistent
with the development of a competitive marketplace. The
continued provision of a fully regulated service
option, as proposed by the various proponents of [price
regulated] service, fails to accomplish that result.
Plan at 88. Moreover, although we recognized the need for such a
service, we noted that the prolonged use of default power service
under the above-described model may have the unintended result of
promoting wholesale rather than retail competition.
Under the Plan, we found that it was appropriate to require
distribution companies to "administer" default power service. We
based our decision on our belief that many customers "may resist
the shift to competition because of the additional effort
involved in arranging their own power supplies." Plan at 89. We
also found that such an approach would minimize customer
confusion and simplify the administration of QF contracts, which
we required distribution companies to use to meet default loads.
Return to TOC
i. Rehearing Requests - Default Service
CVEC asserts on rehearing that the default power
requirement is "deficient" because it does not include a specific
cost recovery mechanism for administering QF contracts. PSNH
argues that the "profitless" pass-through of administrative costs
contemplated in the Plan will fail to provide an incentive for
PSNH to achieve the lowest possible market cost of power and will
result in an uncompensated taking of PSNH's property.
Return to TOC
ii. Commission Conclusions - Default Power Service
In the Plan, we established a new service obligation on
the part of incumbent utilities, i.e., to serve as the
administrator of default power service. We loosely defined this
service as unbundled generation service that does not require
customers to deal directly with competitive suppliers. The
purpose of this new service was to ensure that customers who
"choose not to choose" would be provided with a reliable, market-
based power supply. For the reasons explained below, it is
essential for us to supplement our prior discussion and amend the
Plan to the extent that it placed power supply obligations on
incumbent utilities.
The model for providing default service which we
established in the Plan required incumbent utilities to make new
wholesale power purchases (as a result of a competitive bidding
process) and to resell that power to default customers. With the
exception of QF obligations, we expressly prohibited utilities
from utilizing existing power supply arrangements to meet the
needs of default customers. Our objective was to allow all
customers, including those whose participation in the retail
market is delayed or interrupted, to realize cost savings
available in the competitive power market.
Since we issued the Plan, however, we have identified
several potential problems associated with this approach which
may seriously undermine the foregoing policy objectives.
Primarily, we are concerned that the approach articulated in the
Plan may provide former wholesale requirements suppliers with the
opportunity to seek recovery of stranded costs at FERC beyond
those which this Commission might allow. This opportunity
could arise only if we require incumbent utilities to administer
default service in a manner which would involve such utilities
becoming an unbundled transmission customer of their former
requirements supplier. While we disagree that default service
obligations on the part of incumbent utilities would trigger any
wholesale stranded cost liability, we are nonetheless concerned
about the potential for such disputes.
Secondly, we are concerned that the default service
paradigm established in the Plan could be misconstrued as merely
an extension of the incumbent utilities' historic obligation to
provide bundled energy service to retail customers at regulated
rates. We disagree: we intend default service to provide a
temporary safety net for customers who "choose not to choose" and
to complement retail competition by imposing a new more limited
obligation on the part of incumbent utilities to ensure that all
customers receive energy service.
Although we disagree that the default service paradigm
articulated in the Plan represents an extension of a utility's
historic service obligation, we will vacate that part of the Plan
and instead entertain proposals from competitive suppliers to
serve the energy requirements or demands of default customers.
We will no longer require incumbent utilities to purchase power
on behalf of any retail customer, including default customers.
We invite additional comments from parties on specific models
under which third-party suppliers would serve default customers
directly as a result of a competitive bidding process. Those
comments should be submitted by April 6, 1998. Following a
review of these comments, we will issue a separate order
addressing bidding parameters. We will also consider specific
proposals by distribution companies to serve default customers
provided that such proposals would not trigger stranded cost
filings at FERC. Any proposal to serve the customers within a
specific utility's service territory should be submitted within
that utility's compliance proceeding. We will also consider
proposals to provide default service on statewide basis.
This decision requires us to revisit our policy concerning
the use of QF power to supply energy to default customers. See
Plan at 89-90. Specifically, we direct utilities to resell
energy and capacity purchased under QF agreements into the
wholesale power market as part of their overall obligation to
mitigate above-market costs. Specific proposals should be
included in compliance filings.
Based on the foregoing, the specific requests for
clarification filed by PSNH and CVEC are moot.
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n. Transition Service
i. Comments on Transition Service
By letter dated January 12, 1998, the Commission
allowed the parties an opportunity to submit comments on
"transition service," which is a new service that has been
proposed by various parties to supplement the provision of
default service. Governor Shaheen, Cabletron, Enron, GSEC,
OCA, PSNH, RMA and Unitil submitted written comments, which we
summarize below.
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(1) Nature of the Service
GSEC states that transition service should be an
optional service that "is similar in kind and quality to what
[customers] receive today, but which would also offer them the
benefits of a competitive generation market." The OCA believes
that transition service should be an unbundled service and that
the names of suppliers should be displayed on customer bills.
PSNH describes transition service as a "full service option" for
customers who choose not to select a competitive supplier. PSNH
does not specify whether its service should be bundled or
unbundled.
With the exception of Enron, all commenters appear to
advocate the same transition service paradigm, that is, a service
administrator (either a distribution company or an independent
third party) would acquire sufficient power in the wholesale
market through a competitive bid and then resell that power at
regulated rates to retail customers. Enron, by contrast, would
eliminate the "middle-man" and allow competitive suppliers to bid
to serve all or parts of the transition service load directly.
Under Enron's proposal, transition service would become a pure
retail transaction.
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(2) Eligibility
GSEC and PSNH state that all customers who "choose not
to choose" should be eligible for transition service. The OCA
and PSNH believe that transition service customers should be able
to terminate service at any time, but should not have an
unlimited right to return. The OCA proposes a 120 day window,
beyond which customers must take default service or purchase
directly from competitive suppliers. PSNH proposes that only
residential customers be allowed to return, provided they do so
within 90 days after choosing a competitive supplier.
PSNH proposes that transition service be offered for a
period no shorter than three years and no longer than seven.
Transition service customers should also be eligible, according
to PSNH and the OCA, for default service at the end of the
transition service term. GSEC believes that the service should
serve as a transition tool and provide customers with an
incentive to move to the competitive market. In order to
accomplish that goal, GSEC recommends that the term be limited to
three to five years with annual caps that escalate over time
placed on the price of energy.
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(3) The Need for Transition Service
GSEC contends that customers should have the option of
taking transition service because service choices and quality
information may be in short supply in the early years of retail
competition. GSEC also suggests that the region's current tight
capacity situation may make it difficult for some customers to
obtain attractively priced energy supplies in the competitive
market. Price guarantees can be secured, according to GSEC, by
the establishment of annual caps on the price of energy. PSNH
concurs and suggests that all utilities negotiate "backstop"
agreements with power suppliers so as to limit transition service
energy prices consistent with specified "overall rate targets".
Customers taking default service would not, according to PSNH,
receive these price assurances. The Governor also believes that
it may be appropriate in some circumstances to limit transition
service prices in order to guarantee customer savings and smooth
the path to competition.
Unitil contends that the establishment of a below-
market, standard offer service similar to those offered in Rhode
Island and Massachusetts would deter the emergence of new
competitors in New Hampshire, impede the development of fair and
efficient energy markets, and increase costs for future
customers. Concurring, Enron asserts that the adoption of
inappropriate market proxies in other jurisdictions has delayed
the transition to full competition. If a price cap is deemed to
be a necessary component of transition service, Enron suggests
that the Commission utilize either the LaCapra market price
estimates or the average clearing prices for energy, capacity,
and ancillary services available through the regional power
exchange.
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(4) Power Supply Issues
All commenters agree that power supplies for transition
service should be acquired through a competitive bid. GSEC
states that bidders must be "qualified" but does not specify the
qualification requirements. The OCA states that suppliers should
register with the Commission to provide transition service and
must commit to a strict code of conduct. Enron believes that
affiliates of a distribution company should be prohibited from
bidding if the distribution company administers the bid. PSNH,
on the other hand, believes that adequate safeguards can be
developed to protect against affiliate abuses. The Governor
suggests that it may be appropriate to limit the involvement of
affiliates in the bid process.
Unitil believes that a market-based transition service
can be implemented without overturning existing multi-state
settlements. By requiring all utilities to put transition
service out to bid, and directing those with guaranteed below-
market power supply agreements to auction the rights to that
power and credit the profits against stranded costs, Unitil
argues that customers can enjoy both the benefits of the
competitive market and the benefits of favorable power supply
agreements.
PSNH and Enron also made suggestions to reduce stranded
costs through the bid process. PSNH suggests that if the bid
produces prices below its proposed backstop level, the resulting
power cost savings should be used to reduce stranded cost charges
instead of transition service charges. Enron proposes the
establishment of bidding criteria that encourage bidders to
include in their bids up-front payments. The up-front payments
from winning bidders would then be used to offset stranded costs.
Enron also supports the proposal in the Governor's September 29,
1997 legal and policy memorandum to mandate the selection of at
least three bidders.
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(5) Administration
GSEC and PSNH believe that transition service should be
administered by distribution companies. The OCA contends that
the provision of transition service by distribution companies
raises important jurisdictional and anti-competitive concerns and
suggests that an independent third party be selected for each
service area. In the alternative, the OCA argues that
distribution companies should offer an aggregation service and
not take title to the power.
(6) Implementation Issues
Unitil argues that whatever policy the Commission
adopts on transition service, it must be applied uniformly in all
service areas. A piecemeal approach to transition service,
according to Unitil, would balkanize the emerging competitive
market and thwart competition. GSEC, on the other hand, believes
that the Commission's transition service policy should allow
terms and conditions to vary from utility to utility. The
Governor believes that the Commission's policy should encourage
consistency across distribution companies, while allowing room
for utility-specific negotiations.
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ii. Commission Conclusions - Transition Service
We begin with the question of whether there is a need
to add a transition service option, particularly in light of the
availability of default service. After carefully reviewing the
comments of parties on this subject, we have concluded that our
new model for default service can achieve the same objectives as
those advocated by proponents of transition service. In both
service models, the power supplies to meet the needs of default
power customers would be acquired through a competitive bidding
process. More importantly, the reason for establishing such a
service is the same as that which caused us to create default
service: to allow retail customers to realize some of the
benefits of competition without requiring them to deal directly
with competitive suppliers.
Some commenters believe that transition service is
necessary to achieve other objectives, in particular, stable and
predictable energy prices. We disagree. This argument appears
to be premised upon an assumption that our default model cannot
achieve these pricing goals. On the contrary, default service
model can achieve these objectives through the use of appropriate
bidding rules and selection criteria. One way, for example, is
to require bidders to submit bids which include prices that are
known in advance and do not vary significantly over time. For
all of these reasons, we believe it is unnecessary to add a third
service option at this time.
In light of the foregoing observations, we will address
the outstanding comments concerning transition service as a
supplement to our prior discussion on default service. From this
point forward, however, we will no longer refer to a separate
default service, believing that transition service more
accurately depicts the nature and availability of the service
added herein.
We continue to believe that transition service should
be available for no more than 60 days to large customers who have
made the transition to the competitive market, and who for one
reason or another, find themselves temporarily without a
supplier. However, because of the anticipated need to educate
small commercial and residential customers about retail access,
transition service will be available to those customers for at
least one year period beginning on the date that competition
commences and continuing until such time as the Commission makes
the determination that such transition service is either no
longer necessary or should be modified as the result of
experience with the competitive market.
In our view, large customers have the ability to make
informed decisions and there will be competitive suppliers who
will be ready to serve them. The evidence in our pilot program
reinforces this observation, and we believe the predicted modest
level of market activity in other New England states over the
next few years may benefit New Hampshire customers. We are
particularly concerned that broadening the availability of
transition service to large customers would hinder retail
competition and would send the wrong signal to potential
competitors about the State's policy objectives which are clearly
articulated in RSA 374-F. Accordingly, we affirm our decision to
allow only those customers with maximum demands of less than 100
kW to use transition service at the start of retail
competition.
We decline Enron's invitation to prohibit affiliates of
distribution companies from participating in the transition
service bidding process if the service is administered by the
distribution company. As discussed above, we are no longer
requiring distribution companies to administer this service.
Also, we believe that the interests of those customers and non-
affiliated competitors can be adequately protected by appropriate
affiliate transaction rules. We agree, however, with the
suggestion to limit the percentage of transition service load
that any single supplier can serve in each distribution company's
service area.
We agree with Unitil that any policy on transition
service should be applied uniformly statewide. It would be
unfair to potential competitors (including affiliates of other
distribution companies) and harmful to retail customers to allow
one utility to incorporate features in its transition service
that limit the ability of competitors to compete while requiring
others to fully open their markets. While we understand the
desire to establish predictable prices for transition service, we
question the wisdom of achieving that objective by placing
artificial constraints on the outcome of a competitive bidding
process. The Legislature has decided that retail competition
will lead to a more efficient industry structure and reduce costs
to customers in the long term. As a general matter, artificial
restrictions on the ability of competitors to compete and on the
ability of customers to choose are inconsistent with the
Legislature's policies and inevitably will lead to higher costs
in the long term. We reaffirm our commitment to rely upon market
forces to achieve the policy goals articulated by the Legislature
in RSA 374-F.
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o. Energy Efficiency
As part of the Plan, the Commission examined whether
distribution companies should continue to plan and administer
ratepayer subsidized energy efficiency programs after the
implementation of retail access. This issue received extensive
comment from parties both supporting and opposing the
continuation of such programs. In the Plan, the Commission
announced its intention to phase out ratepayer-subsidized
conservation programs within two years of implementation of
retail choice. We stated our belief that cost-effective energy
efficiency programs have been and will continue to be valuable
but focussed on the role of the regulated distribution company in
a retail choice environment. We found that today's programs,
based predominantly on long-term avoided cost projections of
generation, would not be appropriate for a distribution company
to administer. See Plan at 111. We stated our belief that
industry restructuring would lead to the increased development of
competitive markets for energy efficiency services and that
ratepayer-subsidized programs administered by distribution
companies could impede the development of this continually
evolving market. Plan at 112.
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i. Rehearing Requests - Energy Efficiency
CLF, on behalf of itself and others who are part of the
Electric Utility Restructuring Collaborative (collectively, CLF),
GSEC and the Governor's Office of Energy and Community Services
(ECS) disagree with our findings on energy efficiency and filed
for rehearing. Cabletron opposed ECS's motion for rehearing.
CLF states that in passing RSA 374-F, the Legislature
gave the Commission specific directives concerning public policy
issues such as energy efficiency, renewable energy resources and
the environmental effects due to restructuring. In CLF's
opinion, the Plan violates those directives and results in
"unsound and unreasonable" policy which the Commission should
reconsider. CLF disagrees with many of the Commission's
findings, especially the two-year phase out of utility sponsored
programs, and argues that the Plan did not address market
barriers, lost opportunities, or the lack of incentives for
energy efficiency programs. Based on RSA 374-F:3, X, CLF argues
that the Plan violates the mandate of the Legislature and wrongly
focusses on the distribution company and its avoided costs upon
which to measure the cost effectiveness of energy efficiency
programs. CLF argues that utility sponsored energy efficiency
programs are for the benefit of ratepayers and society,
generally. The Commission's current benefit-cost test, the Total
Resource Cost test, is appropriate, therefore, to evaluate energy
efficiency programs. CLF agrees with the Commission's
observation in the Plan that the State's experience in the last
few years with utility sponsored energy efficiency programs, with
one exception, has been disappointing, but believes this is
because not enough utility-sponsored programs have been approved
and funded.
CLF urges the Commission to adopt a 3.2 mills per kWh
wires charge to fund energy efficiency programs and a 0.3 mill
per kWh charge for renewables commercialization and to establish
working groups to recommend to the Commission how to best
implement commercialization programs for energy efficiency and
renewable resources. CLF also asked that the Commission revise
the Plan to support comparable emissions standards for all power
plants.
We granted the rehearing requests to address a number
of specific issues concerning energy efficiency: market barriers,
market-based incentives, the appropriate benefit-cost test,
program administration, and impact on near-term rate relief. See
Order No. 22,576 (April 30, 1997).
We received written comments and testimony from a
number of parties and Commission Staff concerning energy
efficiency and environmental and renewable energy issues.
Additional comments were received from current and past members
of the Legislature and from an energy services company. The
Commission took evidence in a full day of panel discussions on
October 9, 1997.
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ii. Comments on Energy Efficiency and Other Public
Policy Issues
(1) Market Barriers
The proponents of continued electric utility funding
for energy efficiency programs, CLF, GSEC, ECS, Save Our Homes
Organization (SOHO), National Association of Energy Service
Companies (NAESCO) and the Northeast Energy Efficiency Council
(NEEC), argue that market barriers exist which prevent or impede
the full development of private market-based energy efficiency
services; utility sponsored and ratepayer-subsidized programs are
necessary, therefore, to reduce or eliminate the market barriers.
Those market barriers most often cited include the high discount
rates of customers, the uncertainty of benefits associated with
energy efficiency products, the split incentives between users of
energy and the owner or builder of the facility, the high initial
cost of the product and the information and transaction costs
associated with energy efficiency products. Some parties cited
the absence of including all the environmental costs of supply-
side options in the price of the product as a market barrier for
customers to choose energy efficient products.
Most of the comments focused on the market barriers
faced by residential and small commercial customers and the need
to keep ratepayer funded programs during a transitional period as
a way to reduce the market barriers. CLF, CRR and ECS propose
funding levels they believe are necessary to reduce market
barriers during the transition. GSEC proposes funding programs
for its customers as they are funded today.
Others, such as Staff and LighTec, disagree. LighTec
states that the "[l]argest single barrier to the growth of a
competitive energy service's industry ... will be an improperly
planned and implemented rebate program." LighTec believes that
utility owned energy service companies have distinct advantages
in providing programs to their distribution company affiliates.
LighTec does not believe any ratepayer subsidies are needed for
energy efficiency programs; in fact, LighTec states that
subsidies can harm more than help energy efficiency programs.
Staff questions the market barrier argument on a number
of grounds. Arguing that this market is, and has always been,
subject to some degree of competition, Staff contends there is no
market failure in this area, and, consequently, there is no
reason for the Commission to assert regulatory power over this
segment of the economy. Staff equates the market barrier
argument with the "infant industry" argument often used by
countries to protect uncompetitive industries in trade
agreements. Staff does state, however, that the existence of
market barriers is an empirical question, ultimately, and one
that could use more study.
Unitil fully supports a transition to a competitive
market for a non-subsidized, market-based energy efficient
services industry. Unitil states that continuing ratepayer-
subsidized DSM programs may itself be a market barrier to
reaching a fully developed market for energy efficiency products.
Unitil supports a working group to identify market barriers and
recommend solutions to reduce or eliminate those market barriers
in as short a time as possible.
NHEC believes its non-profit status as a member-owned
utility gives it a different perspective on energy efficiency and
the market barriers faced by its members. NHEC states that large
energy service companies are not interested in providing services
to NHEC's rural service territory and, therefore, NHEC-sponsored
programs provide a valuable mechanism to reduce information
barriers faced by its members.
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(2) Market-Based Incentives
CLF and others believe market-based incentives work
well to support and complement utility sponsored programs. They
cite upgrades to building codes and the disclosure of accurate
and clear information as necessary and helpful for successful
market-based programs. NAESCO believes that a properly
structured, ratepayer-funded standard performance contract is the
best way to support and encourage the private energy efficiency
market. A standard performance contract would use direct
interaction between suppliers and customers of energy efficiency
products as well as serve as a valuable educational mechanism.
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(3) Cost-Effectiveness Test
CLF, GSEC, ECS and others believe energy efficiency
programs should be viewed and evaluated from a societal
perspective which includes all societal costs and benefits such
as avoided transmission and distribution costs as well as the
benefits associated with avoided generation. Staff argues the
Commission should maintain its current methodology, the Total
Resource Cost test; GSEC argues for the electric system test. A
number of parties believe this is an issue that could be better
addressed by a working group.
Staff described the five basic benefit-cost tests used
to evaluate energy efficiency programs. Due to the adverse
effect of utility sponsored programs on non-participants and the
market, Staff supports the use of the Rate Impact Measure test
during the two-year phase out period.
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(4) Program Administration
NAESCO believes that, to reach a vibrant private
energy efficient marketplace, adoption of strong affiliate
standards of conduct are necessary. LighTec argues that an
affiliate of either the distribution or supply company should not
be associated with the administration of energy efficiency
funding due to the potential conflicts; an independent third
party should be used. Because of its unique utility status, NHEC
believes that it should administer programs for its members.
GSEC also believes utilities should administer utility sponsored
Demand Side Management (DSM) programs as well as be allowed to
participate in regional market transformation efforts. ECS
stresses that certain concerns about programs impeding private
market development, such as the equitable treatment of rebates,
are due to program design and not a reason to eliminate public
support for cost-effective energy efficiency programs. ECS
believes that one goal of a working group should be to ensure
that private market initiatives are not hindered by utility-sponsored programs.
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(5) Impact on Near-Term Rate Relief
Staff examines the sensitivity of rates to various
levels of utility-sponsored energy efficiency programs. Staff's
quantitative analysis, based on PSNH rates and funding,
indicates that near-term rate relief is seriously harmed
depending on the level of funding and the recovery by utilities
of lost fixed costs.
NHEC believes its DSM programs, whose costs account for
1% of its rates, should be continued because they provide an
excellent return to members, both those that benefit directly and
those that do not. NHEC does not quantify that return, however.
GSEC states that funding would be at its current levels and
designed to provide rate reductions to all its customers though
it does not elaborate on how, in a competitive retail market, all
distribution customers would benefit.
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iii. Commission Conclusions - Energy Efficiency and
Other Public Policy Issues
Based on the extensive record before us, we affirm, in
part, and vacate, in part, our positions in the Plan regarding
utility sponsored energy efficiency programs, renewable energy
and the environmental aspects of electric utility restructuring.
In taking this action, we note the language of RSA 374-F:3, X
which states:
Restructuring should be designed to reduce market
barriers to investments in energy efficiency and
provide incentives for appropriate demand-side
management and not reduce cost-effective customer
conservation. Utility sponsored energy efficiency
programs should target cost-effective opportunities
that may otherwise be lost due to market barriers.
We continue to believe that the most appropriate policy is to
stimulate, where needed, the development of market-based, not
utility sponsored and ratepayer funded, energy efficiency
programs, a principle that the Legislature incorporated into RSA
374-F. However, the Legislature has also recognized the value of
some utility sponsored energy efficiency programs, which we
believe our plan must address.
We recognize that the transition to market based
programs may take longer than the two-year period we mandated in
the Plan, though we continue to believe that such a transition
period is an appropriate policy objective. We also recognize
that there may be a place for utility sponsored energy efficiency
programs beyond the transition period, but these programs should
be limited to "cost-effective opportunities that may otherwise be
lost due to market barriers." We believe that efforts during the
transition toward market-based DSM programs should focus on
creating an environment for energy efficiency programs and
services that will survive without subsidies in the future.
We still need to determine what is the appropriate test
for determining "cost-effectiveness." We are not prepared today
to choose among the methodologies available for determining cost-
effectiveness. We recognize and would like others to recognize
that cost-effectiveness in a competitive energy environment
differs from the way cost-effectiveness has been viewed
previously. We believe that the best way to proceed is to create
a working group, as advocated by a number of parties, to help us
develop standards for evaluating energy efficiency programs as
outlined in more detail below and to assist us in designing an
appropriate cost-effectiveness test that we will apply to future
programs. Until we receive guidance from the working group on an
appropriate cost-effectiveness test, we will continue the use of
the TRC test, based on the use of a market price as the proxy for
avoided cost, to evaluate DSM programs. We direct utilities to
cap their program funding at existing levels until we have
received and ruled upon the working group's recommendations.
Funding includes direct program costs, lost revenues and utility
financial incentives.
We emphasize that the working group will need to take a
fresh look at utility sponsored energy efficiency programs, one
that, in the words of ECS should "build in obsolescence wherever
possible" and "transform markets." We can not emphasize enough
our belief that these programs must complement the new energy
markets, and not hinder their development. This will be true of
programs that will be allowed during the "transition" away from
most utility sponsored programs, as well as programs that will
survive that transition because they would "otherwise be lost due
to market barriers." These guidelines should assist utilities
and our Staff in preparing and reviewing DSM programs in the
interim as well as to assist the working group in helping us to
prepare for a very different future. We also believe that it is
appropriate to move as quickly as possible from the payment of
lost revenues as part of any DSM program. Finally, we reaffirm
our position in the Plan that distribution utilities should, at a
minimum, undertake energy efficiency programs that avoid more
costly distribution system alternatives.
We note that the Legislature is considering HB 587. HB
587 would limit for some distribution utilities the total
systems benefit charge for energy efficiency and low income
energy assistance programs. If enacted, it would obviously
affect the working group's recommendations and our decisions in
this area.
With these guidelines in mind, we ask the working group
to address the following:
- what is the appropriate cost-effectiveness test for
future program evaluation and whether there should be a
different standard to evaluate cost-effectiveness of
transformation programs.
- what, if any, market barriers exist, and what the
alternatives are to reduce or eliminate these barriers
during the transition to market-based programs. We
believe the working group and others should recognize
the effect our public education program may have on
reducing informational barriers.
- how the Commission can quantitatively evaluate the
effects of these alternatives during the transition.
- what "market transformation" initiatives are needed to
stimulate market development of energy efficiency
products and services.
- for each market barrier identified, provide a
measure(s) that the Commission can use to evaluate the
significance of the market barrier as well as how the
Commission will know when the barrier is no longer
significant.
- what level of funding is appropriate for low-income
energy efficiency programs and does sufficient funding
exist in the $13.2 million low-income system benefits
charge to use for energy efficiency programs for
eligible low-income customers. We remind the working
group and others that the $13.2 million low income fund
was intended not only to make bills affordable but also
to encourage conservation and energy efficiency to make
bills manageable. Plan at 95.
- what the effects are of utility-sponsored programs on
rates and how will the costs of these programs be
collected through rates.
- whether all large commercial and industrial customers
should contribute to utility-sponsored DSM programs,
even if they do not participate in the programs or
receive transition service.
We believe a diverse group representing utilities, low income
assistance advocates, energy service providers and conservation
and environmental groups, as well as representatives of affected
public agencies such as ECS, the State's Air Resources Division,
and OCA would contribute significantly to resolving the issues we
outlined above. Interested parties should contact our Executive
Director.
We have also considered the requests for a renewables
commercialization program and the imposition of certain
environmental regulations on all fossil generation sources
participating in New Hampshire's retail choice market. We will
deny both requests. While we understand the rationale for such
requests, and may agree in principle with the suggestion to make
old and new plants meet the same emissions levels as a way to
rectify certain infirmities in the Clean Air Act Amendments of
1990, we reaffirm our position in the Plan that the setting of
incentives and standards for compliance with air quality
regulations should be left to the United States Environmental
Protection Agency and the New Hampshire Department of
Environmental Services. To the extent energy efficiency programs
are used in the future as offsets to more costly environmental
compliance programs, we believe the enactment of such programs
will serve to further the development of cost-effective, market-based programs.
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p. Supplier Registration
On May 22, 1997, we received a recommendation for supplier
registration requirements from the working group which was
established to consider that issue. We have reviewed the
proposed requirements and find them to be an appropriate starting
point for a rulemaking on supplier registration. Accordingly, we
will open a rulemaking docket to address the issue of supplier
registration and related consumer protection issues. Parties
interested in participating in the rulemaking proceeding should
contact our Executive Director.
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q. Public Education Plan
In our Plan, we established a working group to advise us on
the development of a public education program and stated that we
would hire a consultant to put the program together for us. On
December 19, 1997, our consultants, HighPoint Communications
Group and Gregory S. Franklin Associates, submitted a proposed
plan for a public education program which the working group
recommended we adopt. RSA 374-F:3, II states that "the
commission should ensure that customer confusion will be
minimized and the customer will be well informed about changes
resulting from restructuring and increased customer choice." We
have reviewed the plan, given consideration to the
recommendation of the working group and the comments received
from the parties and find that the proposed plan meets the
legislative directive.
Although the cost of implementing a statewide public
education program is substantial, we continue to believe that a
comprehensive public education program is essential to the smooth
transition to a competitive market. The research conducted by
our consultants during the development of the public education
plan furthers supports this belief and strengthens our conviction
that a public education program is an integral piece in the
successful opening of the competitive market. We have looked at
what other states have done in terms of public education and
believe the proposal from our consultants is comprehensive and
cost effective. We have done some comparisons of the cost of the
plan proposed by our consultants, on a per capita basis, to those
proposed and adopted elsewhere and find the proposed program
reasonable and affordable. Accordingly, we will adopt the
proposed plan submitted to us by our consultants and direct the
public education working group to move forward with the
development of a request for proposals to solicit bids for the
implementation of the program.
How the public education program will be funded still
remains outstanding. RSA 365:37, II permits us to assess the
utilities for costs of experts or other assistants hired by the
Commission. While many suggestions have been made regarding
funding, we believe that the simplest and most appropriate method
of funding the program is through a utility assessment. We
direct the utilities to include in their compliance filings
proposals for the recovery of the public education costs assessed
against them.
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4. CONCLUSION
Based on the foregoing, the Commission's February 28, 1997
Plan is clarified and modified as stated herein. Unless
otherwise specified in this order, the Plan is affirmed. Finally
the Commission affirms the ISC orders for Connecticut Valley
Electric Company, Inc. (Order No. 22,809), Granite State
Electric Company (Order No. 22,511), New Hampshire Electric
Cooperative, Inc. (Order No. 22,513) and Unitil Power Corporation
(Order No. 22,510).
By order of the Public Utilities Commission of New Hampshire
this 20th day of March, 1998.
Douglas L. Patch Bruce B. Ellsworth Susan S. Geiger
Chairman Commissioner Commissioner
Attested to:
Thomas B. Getz
Executive Director and Secretary
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APPENDIX A
UPDATE ON REGIONAL ACTIVITIES: NEPOOL REFORM
In RSA 374-F:3 XIII., the Legislature recognized the need to
reform the New England Power Pool (NEPOOL) to enhance competition
and complement industry restructuring on a regional basis and
directed the Commission to work with other New England and
northeastern states, where possible, to accomplish the goals of
restructuring. In the Plan, the Commission identified strengths
and weaknesses of NEPOOL's reform proposal and discussed its
commitment to working with other New England states to develop,
where possible, consistent and mutually beneficial policies and
requirements to ensure that the institutions established to
facilitate competition in the region can successfully do so. The
Commission has worked closely with other New England states to
identify elements of NEPOOL's proposal which were likely to
impede the development of competition in New Hampshire or the
region. Through the New England Conference of Public Utility
Commissioners (NECPUC), the Commission provided NEPOOL with
suggestions to improve the proposed market model, focusing on two
broad areas: the structure, governance and financing of the ISO
and issues relating to market power.
On February 20, 1997, the Commission, through NECPUC, filed
comments with the FERC supporting NEPOOL's proposed ISO on an
interim basis and requesting that FERC instruct NEPOOL to develop
a permanent funding mechanism that assures budget independence,
such as a transaction based fee. NECPUC also expressed concern
that, as proposed, the ISO would disseminate information provided
to it by NEPOOL Participants in accordance with the NEPOOL
Information Policy. Our concern was assuaged somewhat by the
fact that the ISO ultimately had the authority to change pre-
existing System Rules and Procedures when it determined that such
a change was necessary. We continue to believe that the ISO
should establish its own information policy that ensures that
non-NEPOOL market participants are not disadvantaged by
information flow to NEPOOL Participants.
On the same day that the Commission issued its Plan, the
FERC accepted for filing the NEPOOL restructuring proposal and
made it effective, subject to refund, after a nominal suspension,
on March 1, 1997. The FERC order allowed NEPOOL to begin taking
service under the proposed transmission tariff by March 1, 1997,
in compliance with Order 888. However, the FERC deferred action
on the merits of the filing, leaving many disputed issues
unresolved.
On June 25, 1997, the FERC conditionally authorized the
establishment of an ISO by NEPOOL and made an interim finding
that the transfer of control of jurisdictional transmission
facilities owned by the public utility members of NEPOOL to the
ISO was consistent with the public interest under section 203 of
the Federal Power Act. Some of the conditions which FERC placed
on its approval required the ISO to: lower the definition of an
affiliate from 50% to 10% ownership; adopt a self-funding
mechanism; ensure that ISO employees are financially independent
of market participants by divesting any financial interests in
market participants; and eliminate the restriction limiting
NEPOOL membership to New England entities.
FERC also conditioned its approval on NEPOOL's agreement to
modify the Interim ISO Agreement to obligate (rather than simply
authorize) the ISO to review the long-range system assessment and
transmission construction plans of NEPOOL Participants. In
addition, FERC's ISO principle number 6 requires that ISOs be
able to take operational actions to relieve system constraints
within the trading rules established by the governing body.
Although NEPOOL stated that the ISO would administer the proposed
bid-based power exchange, NEPOOL failed to file bid-based rules.
Consequently, FERC deferred action on this aspect of NEPOOL's
filing.
On May 1, 1997, NEPOOL supplemented its restructuring
proposal by filing market power mitigation principles and
procedures which would be applied during transmission
constraints. In essence, when the ISO dispatched a resource out
of economic merit during a constraint, the ISO would apply two
screens: a market structure screen, intended to evaluate
competitive alternatives to the dispatched resource, and a price
screen, intended to identify whether the price of the resource
has been raised substantially, persistently or repeatedly (during
constraints). NECPUC retained two consultants to evaluate
NEPOOL's proposal and to conduct independent studies of market
power in New England. A fundamental conclusion of both
consultant reports was that the NEPOOL analysis relied upon
questionable assumptions, was biased and inconclusive. More
analysis was needed before the New England electric generation
markets could be opened to competition.
As we indicated in the Plan, the Commission favors a
collaborative approach to NEPOOL restructuring, and has worked
with NECPUC, NEPOOL and with the newly formed ISO to improve the
proposed market model. In addition, we directed our staff to
work with NECPUC to engage NEPOOL and the ISO in intensive
discussions regarding the market power monitoring and mitigation
proposal to better understand the areas of and reasons for
disagreement. In our comments at FERC, we identified several
important questions which we believed must be answered before we
could support a request for market based rates and which guided
staff's discussion with NEPOOL and the ISO. Specifically, these
questions included: What should the ISO monitor? What triggers
or benchmarks are relevant in each of the product markets? What
information will be available to the ISO to assist it in
monitoring the market? How much, if any, of that information
should be kept confidential? Will stakeholders be permitted to
audit the monitoring data? Should monitoring reports be
prepared, and if so, who should have access to the reports and
the underlying data?
On December 19, 1997, NEPOOL filed with FERC, a market
monitoring, reporting and market power mitigation proposal in
support of market rules. This latest proposal by NEPOOL reflects
the dialogue among NEPOOL, the ISO and NECPUC.
As stated in the Plan (at 34), this Commission has a vital
interest in ensuring that the prices determined through the power
exchange (PX) are not subject to manipulation. This requires the
implementation of rules that promote economically efficient
trading and an entity both authorized and obligated to monitor
activities in the evolving competitive marketplace. The
Commission believes that the proposal developed by NEPOOL and the
ISO represents a sufficient starting point. This support is
conditioned on the parties continuing to work to build consensus
and resolve the issue of appropriate sanctions for physical
withholding of capacity and failure to comply with market power
monitoring or mitigation orders of the ISO. We also believe that
additional work must be done to clarify how the ISO will identify
anomalous behavior by a generation supplier. Although NEPOOL and
the ISO assert that their proposal contains both structural and
behavioral components, we believe their proposal's value lies in
its review of participant behavior. Although market share
numbers provide some indication of the degree of competition in a
market, we believe they are insufficient to evaluate whether the
changes that have taken place in the market serve the public
interest. Consequently, we believe that the ISO, in keeping with
its obligation to evaluate the efficiency and competitiveness of
the markets, be required to include in its reports, analyses of
the relationships between bid and clearing prices to marginal
costs. Further, decisions regarding the recoverability of
stranded costs by each state in the region will affect the
bidding decisions of suppliers and, therefore, may affect the
market price as determined by the power exchange. Consequently,
it is appropriate for the ISO to consider these issues as it
evaluates the developing market.
In addition, because we continue to assert authority over
market structure issues as they affect New Hampshire, we believe
any reports the ISO makes available to NEPOOL Participants, FERC
or other regulatory agencies should be made available to this
Commission. This also means that the Commission maintains its
right to examine the activities of the ISO/PX as they pertain to
the competitiveness of the markets and how they develop. In this
regard, we expect that the ISO will be responsive to our requests
for relevant information, should such a need arise. We recognize
that as the competitive market develops, certain production and
financial data will become increasingly sensitive. Consequently,
we believe appropriate confidentiality arrangements should govern
the treatment of competitively sensitive information.
On January 21, 1998, the NEPOOL Executive Committee advised
the FERC that the ISO would be unable to complete the rules,
computer software and other arrangements necessary to operate
under the proposed new market provisions by the expected April
1st date. On February 9, 1998, the ISO announced a target of the
fourth quarter of 1998 for start-up of the new competitive
wholesale market. We will continue to engage in appropriate
dialogue with the ISO and NEPOOL and offer advice and guidance to
assist them in achieving the goal of implementing the structures
necessary to ensure competitive and efficient markets while
maintaining a safe and reliable system.
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APPENDIX B
SUMMARY OF WORKING GROUP ACTIVITIES
The Commission's February 28, 1997 Plan called for the
establishment of several working groups to address a variety of
issues such as supplier registration, low income assistance,
public education, energy mix disclosure requirements, competitive
metering and electronic data interchange standards. The efforts
of these groups are essential to the successful implementation of
retail choice in New Hampshire, and the groups have moved forward
with their tasks despite the federal litigation. The summaries
below reflect the activities of the various working groups to
date.
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Supplier Registration Working Group
In its Plan, the Commission found that "one of the most
effective and reasonable methods available for ensuring
disclosure of information is the imposition of registrations
requirements" and that "registration requirements should also
provide suppliers with an incentive to behave responsibly". Plan
at 103. On March 18, 1997, an organizational meeting for the
supplier registration working group was held. The group, which
was comprised of representatives of Enron, AllEnergy, EnerDev,
Granite State Electric Company, Public Service Company of NH, NE
Electric System, Cabletron, the Community Action Agencies, the
Governor's Office of Energy and Community Services, NH Legal
Assistance, the Electric Restructuring Collaborative, the Office
of Consumer Advocate and the Commission Staff along with
Representative Clifton Below, met regularly during the spring.
On May 22, 1997, the supplier registration working group
submitted draft rules to the Commission which addressed
registration requirements as well as consumer protection
requirements for competitive suppliers.
The draft rules recommend the Commission establish a minimum
demonstrable level of financial resources for competitive
suppliers and require the disclosure of information that would be
helpful to consumers when choosing a supplier. While aggregators
are not required to register with the Commission, notification of
intent to provide aggregation services is required by the
proposed rules. The rules address the telemarketing concerns
that were raised by consumers and other commenters during the
Commission's restructuring proceedings. Rules prohibiting the
unauthorized transfer of service along with notice provisions for
terminating service are also included. Finally, sanctions for a
supplier's failure to comply with the rules are outlined.
The Commission has opened a rulemaking document for
consideration of the draft proposal submitted by the working
group and will be scheduling a public hearing on the proposed
rules in the upcoming weeks. The proposed rules can be viewed on
the Commission's web page at www.puc.nh.gov.
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Public Education Working Group
Recognizing that a comprehensive public education program
was essential to the smooth transition to a competitive market,
the Commission authorized the formation of a working group and
the hiring of a consultant to assist it in its public education
endeavors. The working group, consisting of representatives of
Granite State Electric, NH Electric Cooperative, Public Service
Company of NH, Unitil, Enron, the City of Manchester, the
Electric Restructuring Collaborative, the Governor's Office of
Energy and Community Services, NH Legal Assistance, the Institute
for Cooperative Development, the Office of Consumer Advocate and
the Commission Staff, issued a request for proposals on April 9,
1997 requesting proposals for the provision of outreach,
educational and communication services related to the development
of a public education campaign. The working group conducted
interviews with the four bidders and submitted a recommendation
to the Commission that the contract be awarded to HighPoint
Communications Group/Gregory Franklin Associates (HighPoint).
After conducting its own interviews, the Commission followed the
recommendation of the working group and selected HighPoint.
HighPoint worked closely with the working group during the
fall and submitted its proposed public education program to the
Commission on December 15, 1997. On December 17, 1997, the
working group submitted its recommendation to the Commission,
endorsing the plan submitted by HighPoint and recommending the
Commission adopt the proposed plan. On January 12, 1998, the
Commission notified all the parties that it had reviewed the
proposed public education plan submitted by HighPoint and
believed it to be a comprehensive, well designed program that met
the goal of providing residential and small business consumers
with the information and tools needed to make an informed choice
in a restructured electric industry. The Commission determined
that it was appropriate, however, to provide an opportunity for
comments on the proposed plan before issuing any ruling.
Comments on the proposed plan were due by February 5, 1998. Two
parties, Enron and Unitil, submitted comments. The Commission
has considered the comments it received from the parties along
with the recommendation of the working group and has, in this
order, adopted the plan submitted to it by HighPoint/Franklin.
An RFP for the implementation of the public education plan will
be forthcoming.
The foundation for the public education program is an
integrated communication plan whose effectiveness comes from the
synergies created through the use of a wide range of integrated,
interdependent communications strategies. Research was used
extensively to insure the plan was based on actual market
awareness, interest and opinion. Benchmark surveys, focus
groups, individual and group interviews and media analysis were
used to determine the key issues, audiences and attitudes this
program needed to address.
The program focuses on two major audiences, residential
consumers and small businesses within New Hampshire. Its
objective is to provide these audiences with the information and
understanding they need to make an informed, knowledgeable energy
choice. In addition, the plan is designed to enable consumers to
understand that with choice comes a range of economic,
environmental and social implications and directs them to other
resources that can further educate them on these issues.
The program, which is based on a series of measurable
awareness, understanding and empowerment objectives, has four
primary objectives: to enable New Hampshire consumers to make
informed, knowledgeable assessments of their electric energy
options in the state's new competitive electric energy
marketplace; to enhance state-wide understanding of the concepts,
principles and processes of retail electric competition within
all target audiences so that polarized positions are minimized
and appropriate, effective and accurate discourse of these
changes is enabled and encouraged; to position the New Hampshire
Public Utilities Commission as the neutral, most reliable
resource and knowledgeable voice concerning the new competitive
electric marketplace; and to minimize marketplace confusion and
reduce the potential for marketing abuses. The program timetable
has a kick-off date approximately 60 to 90 days prior to the
introduction of retail choice and an end date approximately 24
months after the implementation of retail choice. The public
education plan can be viewed on the Commission's website at
www.state.puc.nh.us.
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Low Income Working Group
In keeping with the Legislative directive that "programs and
mechanisms that enable residential customers with low incomes to
manage and afford essential electricity requirements should be
included as a part of industry restructuring", the low income
working group is developing a program to provide assistance to
low income customers. The working group, which includes
representatives of NH Legal Assistance, the Governor's Office of
Energy and Community Services, the Electric Restructuring
Collaborative, Connecticut Valley Electric, Granite State
Electric, NH Electric Cooperative, Public Service Company of NH,
Unitil, the Office of Consumer Advocate and the Commission Staff,
issued a RFP for an administrator for the low income program and
has been negotiating the terms of the contract with the CAP
agencies, the sole respondent to the bid. While the low income
working group has not yet submitted its final recommendation to
the Commission, it recently submitted a status report outlining,
in general terms, its proposed assistance program.
As described in the February 24, 1998 status report, the
proposed low income energy assistance program is a fixed credit
payment program. The guiding principle behind the program is to
bring bills down to an affordable level thereby motivating
participants to change their payment habits and make regular and
timely payments on their utility accounts. The proposed energy
assistance program defines affordable bills as those which are
equal to 4% of income for general use customers and 6% of income
for electric heat customers. The proposed energy assistance
program provides benefits to participants based on historical
usage and income. In order to be eligible for the program, a
participant's income must be equal to or lower than 150% of the
federal poverty level.
For example, a four person household earning $12,000 per
year (75% of the federal poverty level), with a general usage
electric bill of $75 per month currently pays 7.5% of its income
towards the electric bill. Under the energy assistance program,
this same household would receive a monthly credit of $35,
bringing the bill down to $40 per month or 4% of the total
household income.
The working group's status report recommends the CAP
agencies administer the proposed program. It also endorses the
participation of the Governor's Office of Energy and Community
Services in the fiscal oversight of the program, a role the
office currently plays now for the federally funded low income
heating energy assistance program. The Governor's Office of
Energy and Community Services, as part of its fiscal oversight
responsibilities, would monitor the dollars collected versus the
dollars obligated in benefits to participants. It would also
reconcile the dollars collected versus the dollars credited by
the utilities.
The working group expects to submit its completed program
proposal to the Commission by April 3, 1998.
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Electronic Data Interchange Working Group
In order to facilitate the efficient and reliable transfer
of data between regulated distribution companies and non-regulated providers of competitive services, the Commission in
its Plan authorized the establishment of an Electronic Data
Interchange (EDI) Working Group whose purpose was to develop a
consensual plan for the transmission of electronic information
among distribution companies and competitive power suppliers.
The Working Group met for the first time on April 8, 1997 and has
met on numerous occasions since. The group is comprised of
representatives from Connecticut Valley Electric, Granite State
Electric, NH Electric Cooperative, Public Service Company of NH,
Unitil, the Commission Staff, AllEnergy, Enron, Green Mountain
Energy, Strategic Energy Limited, Wheeled Electric Power Company,
Unitil Resources, Xenergy, Eastern Utilities Associates and
Granite State Energy.
One of the first actions of the working group was to create
two subgroups, the Business Rules Subgroup and the Implementation
Subgroup. The task of the Business Rules Subgroup is twofold: to
reach agreement on a standard set of data transactions that meet
the basic needs of all market participants; and to formulate
business rules for each standard transaction. In an effort to
reach consensus on these issues, the subgroup has examined the
relationships between customers, competitive suppliers and
distribution companies as they are anticipated to be at the start
of retail competition. Substantial agreement has been reached on
a set of data transactions that correspond to the anticipated
business relationships, and the subgroup is currently finalizing
description of the business rules that will govern their use.
These rules will apply to each distribution company and all
registered suppliers of competitive products and services.
The Implementation Subgroup's primary task is to review the
technologies and services available for transferring large
quantities of electronic data and to make recommendations which
meet certain technical standards and ensure the timely
implementation of retail choice in 1998. Those criteria include
data security, system reliability and the recoverability and
archiving of data. The subgroup is also responsible for
developing recommendations on the format of the electronic files.
Both of these tasks are substantially complete.
The EDI Working Group recommends that competitive suppliers
attend a mandatory training session that will introduce the
attendees to the regulatory and operational requirements of the
retail electric market in New Hampshire. In addition, each
competitive supplier will be required to demonstrate its
capability to electronically send data to and receive data from
each distribution company in whose service area it intends to
offer competitive services. The training and testing manuals to
implement these requirements are still being developed.
The EDI Working Group expects to submit its final report to
the Commission by April 2, 1998. A draft of the report can be
viewed on the Commission's website.
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Metering Working Group
The metering working group was formed to develop standards
for the competitive provision of metering services to customers
whose maximum demand is in excess of 100 kW. The first metering
working group meeting was held on March 21, 1997, and the working
group met approximately 10 times thereafter. Participants in the
metering working group included representatives from Unitil,
Connecticut Valley Electric, Peregrine Energy Group on behalf of
CellNet Data Systems, Enron Capital and Trade, Granite State
Electric, PJA Energy and Public Service Company of New Hampshire.
The working group has focused on how to best implement
metering technologies and standards, within a competitive energy
marketplace, for customers whose maximum demand exceeds 100kW.
Topics that were discussed at the working group meetings
included:
1) Definition of a > 100kW customer.
2) Load estimation, allocation, and reporting requirements.
3) Data availability, format, and timeliness.
4) Default metering services.
5) Possible barriers to fair competition.
6) Meter accuracy and testing.
7) Meter accuracy dispute resolution.
8) Stranded costs associated with metering equipment.
9) Theft of service issues.
10) National Electric Code requirements.
11) Tax legislation affecting meters (HB 602)
12) Service disconnects and restoration.
13) New metering technologies.
14) Load estimation and reconciliation.
15) Multiple meter logistics.
16) Customer choice versus forced compliance.
Within the context of the meetings, many concerns, issues
and items requiring clarification were raised prompting the
compilation of a "Clarifications & Issues" document that was
submitted to the Commission on August 28, 1997. The Commission's
response to the various issues raised in the working group's
August 28, 1997 request for clarification have been addressed
within the body of this Order. See Commission Conclusions -
Unbundling; Metering and Billing at 8.
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Disclosure of Resource Mix and Environmental Characteristics
of Power Working Group
RSA 374-F:3; VIII requires that increased competition in the
electric industry be implemented in a manner that supports and
promotes the goal of environmental improvement. In the Plan, the
Commission found that, although the parties to this proceeding
held different views regarding the role that the Commission
should play in environmental improvement, the environmental
improvement principle indicates support for "market-driven
approaches." Plan at 113. The Commission stated
although...environmental improvement is an
indispensable public good for which the state and the
nation must make adequate provision, we do not find it
appropriate to independently establish environmental
improvement policies related to electric generators
selling power in New Hampshire. Plan at 116.
The Commission established a working group to discuss issues
related to the disclosure of resource mix and the environmental
characteristics of power and charged the group with developing a
recommendation to the Commission regarding the disclosure of the
energy resource mix and labeling. The Commission further stated:
We also believe ... that customers benefit from
requirements that suppliers disclose information
regarding the environmental characteristics of the
power in their resource mix ... We will also request
that the working group evaluate the feasibility of
requiring suppliers to disclose the environmental
impact of the power in their resource mix.
Plan at 118.
The first meeting of the working group occurred on March 19,
1997. Additional sessions were held on March 27, April 10, 18 and
23, 1997. Representatives from the Commission Staff, the Office
of Consumer Advocate, the Governor's Office of Energy and
Community Services, New Hampshire Department of Environmental
Services - Air Resources Division, the Regulatory Assistance
Project, the Conservation Law Foundation, the Center for Energy
and Economic Development, Green Mountain Power Corporation, New
Hampshire Electric Cooperative, New England Electric System,
Public Service Company of New Hampshire, Granite State Hydro
Association, Enron and Bellwether Solutions participated in the
process. The Legislature was represented by Representative
Clifton Below.
At the working group sessions, several proposals were
presented for consideration. Two, the "Green Tags" proposal
developed by Enron and Green Mountain Power's "Green Disclosure
Standards", were discussed first at a session of the working
group and have since been discussed at the regional and national
level.
Agreement on a number of guiding principles for disclosure
was reached at the April 17 meeting. The working group believes
that customers should receive disclosure information that is
accurate, simple, understandable, objective and verifiable.
Whatever system or systems ultimately chosen should not be
subject to "gaming," which can be generally thought of as the
ability of retail suppliers to evade detection of false or
misleading sales claims due to "loopholes" in the
accounting/settlements process. A universal or standard format
for customers is preferred. How to best achieve those principles
at a reasonable cost is still a matter for further debate and
study. Nonetheless, the efforts of those involved in the working
group will prove valuable as New Hampshire and the other New
England states move closer to the day when all customers will
have the opportunity to choose their retail electric supplier.
The working group submitted the following recommendations
to the Commission: the Commission should impose a moratorium of
12-18 months on disclosure in order to review and analyze
information and data collected through the NEPOOL Settlements
process; the working group should convene a meeting with the
public education working group and the winner of the public
education bidding process to ensure the need for expanded
customer information and education, including information on the
environmental aspects of electricity production is met; the
Federal Trade Commission/ Attorney General/Stakeholders
collaborative should establish disclosure guidelines of
environmental claims; the Commission should encourage, to the
extent feasible, regional consistency in disclosure; and the
feasibility of a "green tag" concept as an element of claim
verification in green market development should be pursued.
The Commission agrees with the working group recommendation
that, where feasible, regional consistency in disclosure
requirements should be pursued. Although we recognize that each
New England state will be developing its own information
disclosure policy, we believe a regional approach is in the
public interest for two reasons. First, such an approach will
assist consumers in comparing suppliers' offers, thereby enabling
consumers to make informed decisions about electricity suppliers
in the region. Second, such an approach will reduce supplier
expenses attributable to compliance with different state
requirements which, in turn, will lower the cost of electricity
in the region. Consequently, we directed our Staff to participate
in workshops organized by the Regulatory Assistance Project.
Those workshops were part of a seven month effort undertaken by
the Regulatory Assistance Project to work with public utility
commissions and other stakeholders in New England in an effort to
develop a uniform regional approach to consumer information
disclosure. The culmination of that effort was RAP's paper
entitled Uniform Consumer Disclosure Standards for New
England: Report and Recommendations to the New England Utility
Regulatory Commissions which included model disclosure
rules. In addition, our Staff continues to work with NECPUC to
consider other disclosure alternatives and to discuss the
feasibility and costs of the various alternatives with the newly
created independent system operator. As a result of their review
process, the NECPUC staff developed model disclosure rules that
built upon the RAP proposal; those model disclosure rules will
serve as the basis for initiating a disclosure rulemaking
proceeding in New Hampshire.
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APPENDIX C
LIST OF PARTIES REQUESTING REHEARING, RECONSIDERATION OR
CLARIFICATION
Public Service Company of New Hampshire (PSNH)
New Hampshire Electric Cooperative, Inc. (NHEC)
Enron Trade and Resources, Inc. (Enron)
Concord Regional Solid Waste/Resource Recovery Cooperative
(Concord Cooperative)
Bio-Energy Corporation, Bridgewater Power Company, L.P., Hemphill
Power and Light Company, Pinetree Power, Inc., Pinetree Power -
Tamworth, Inc., and Whitefield Power and Light Company (Wood-
Fired QFs)
Concord Electric Company and Exeter & Hampton Electric Company
(Unitil)
Cabletron Systems, Inc. (Cabletron)
Retail Merchants Association of New Hampshire (RMA)
Granite State Energy, Inc./AllEnergy Marketing Company, L.L.C.
Granite State Hydropower Association (GSHA)
Governor's Office of Energy and Community Services (ECS)
Office of Consumer Advocate (OCA)
Connecticut Valley Electric Company (CVEC)
Conservation Law Foundation (CLF)
Campaign for Ratepayer Rights (CRR)
Granite State Electric Company (GSEC)
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APPENDIX D
REVISED COMPLIANCE FILING REQUIREMENTS
In accordance with RSA 374-F:4, III, each jurisdictional
utility, except PSNH, shall submit, for Commission approval, a
compliance filing no later than May 1, 1998 consistent with the
Plan (Order 22,514), as modified by this order. Utilities may
address further issues on a voluntary basis.
Utility compliance filings must, at a minimum, include the
following information:
1. A proposed plan to transfer or assign to a non-utility
affiliate (a) owned generation facilities, (b) non-QF
purchases power contracts, and (c) aggregation/marketing
functions.
2. A proposed plan to implement the affiliate transaction rules
adopted by the Commission. For compliance filing purposes,
utilities should use the Commission's draft rules referenced
in Section G,2 of this rehearing order.
3. Documentation showing that the proposed designation of
transmission and distribution facilities as state-
jurisdictional distribution facilities or FERC-
jurisdictional transmission facilities meets the FERC's
seven-factor test.
4. A cost-of-service study which separates 1996 revenue
requirements into the three functional categories of
generation, transmission, and distribution. The
distribution revenue requirement shall be further sub-
divided into distribution, metering, billing, and customer
service; the resulting sub-divisions must be allocated to
rate classes based on the allocation methods underlying
existing bundled rates. Utilities must identify any changes
to previously approved cost allocation methodologies.
5. Proposed tariffs specifying the rates, terms and conditions
for unbundled distribution service to each rate class for
service rendered on or after July 1, 1998. Distribution
service tariffs shall include separate charges for (a)
consumption tax, (b) energy efficiency programs and (c) low
income customer programs. Distribution service tariffs may
also include the non-bypassable stranded cost charges
approved by the Commission in Orders Nos. 22,509 (CVEC),
22,510 (Unitil), 22,511 (GSEC), and 22,513 (NHEC). Revised
ISC charges for PSNH will be set in an order to be issued.
6. A plan to mitigate stranded costs consistent with RSA 374-F:3, XII(c).
7. A proposed method for categorizing customers as "small" or
"large" as those terms are used in the Plan (i.e.,
customer's maximum demand less than or greater than 100 kW).
8. The proposed terms and conditions governing the provision of
standard and consolidated billing services to competitive
suppliers. Under the standard billing option, a customer
receives two bills: one for distribution service from
his/her utility and a second bill from the competitive
supplier for generation service. Under the consolidated
billing option, a customer receives a single bill from the
distribution company for distribution service and generation
service provided by a competitive supplier.
9. A proposed plan to implement the electronic data interchange
requirements of the Plan as amended by this order. Such
plan shall be consistent with the recommendations of the
Electronic Data Interchange Working Group.
10. A proposed plan to implement the low-income customer
policies described in the Plan and the Working Group
recommendations.
11. A proposed plan to meet the energy service needs of special
contract customers.
12. Proposed tariffs specifying the rates, terms and conditions
of an unbundled distribution service to special contract
customers for service rendered on or after July 1, 1998.