DR 98-012
Granite State Electric Company
Offer of Settlement for Retail Choice
Order Approving Amended Offer of Settlement
O R D E R N O. 23,041
October 7, 1998
APPEARANCES: Thomas Robinson, Esq. for New England
Power Company; Carlos A. Gavilondo, Esq. for Granite State
Electric Company; LeBeouf, Lamb, Green & MacRae by Susan Geiser
and Lisa Terrizzi, Esquires on behalf of the Unitil Companies;
Gerald M. Eaton, Esq. for Public Service Company of New
Hampshire; McLane, Graf, Raulerson & Middleton by Steve Camerino
on behalf of Great Bay Power; Sylvester Swierzy on behalf of
EnerDev and Granite State Taxpayers Association; Julie Hashem for
MainePower; Robert Rossignol for Alternate Power Source; David
Parsons for Wheeled Electric Power; James Rodier, Esq. pro se;
Pentti Aalto for PJA Energy Systems; Anne Ross, Esq. on behalf of
Retail Merchants Association; Rubin and Rudman by John Detore and
Donna Sharkey, Esquires on behalf of Enron Capital & Trade
Resources; James Monahan for Cabletron Systems; Foley, Hoag &
Elliot by James Brown, Esq. and Stephen J. Judge and Wynn E.
Arnold, Esquires, for the Governor's Office of Energy and
Community Services; Robert Backus, Esq. on behalf of the Campaign
for Residential Ratepayers; David W. Marshall, Esq. for the
Conservation Law Foundation; the Office of Consumer Advocate by
Michael W. Holmes, Esq. on behalf of Residential Ratepayers;
Eugene Sullivan, III and Robert J. Frank, Esquires, for the Staff
of the New Hampshire Public Utilities Commission.
I. INTRODUCTION AND SUMMARY
In accordance with the public good standard of RSA
374:30 and consistent with the restructuring principles set forth
in RSA 374-F and the recently enacted law, SB 341, as described
below, this order approves the Amended Offer of Settlement
(Amended Settlement) filed by Granite State Electric Company
(GSEC or Company) on July 13, 1998. On February 3, 1998, GSEC
filed a Restructuring Settlement Agreement (Settlement) which was
intended to represent a final and comprehensive resolution of
issues associated with the advent of retail electric competition
in New Hampshire as they pertain to GSEC and its customers. The
Offer of Settlement was supported by a number of parties,
including the Governor, Representatives Bradley and Below,
Senators King and Fraser, and a number of groups and
organizations representing various customer and environmental
interests. A number of parties, including Cabletron, Retail
Merchants Association, James Rodier, the City of Manchester, the
Office of Consumer Advocate, and Staff opposed some parts of the
Settlement, though they indicated they would support the
Settlement with certain modifications.
After extensive testimony, six days of hearings, almost
60 exhibits, and nine briefs, the Commission indicated at a
public meeting on June 26, 1998, that it would approve the
Settlement with some modifications. Those modifications included
changes to transition service, the elimination of the mitigation
incentive payment, a reduction in the post-divestiture cost of
equity for calculation of the contract termination charges,
elimination of that portion of the systems benefits charge
related to a renewable energy commercialization fund and changes
to the Settlement's proposal on energy efficiency to conform with
Order No. 22,875 (March 20, 1998), the Commission's Order on
Rehearing in Docket No. DR 96-150, the generic docket on
Restructuring New Hampshire's Electric Utility Industry.
In its cover letter to the July 10, 1998 Amended
Settlement, GSEC indicated that all signatories to the Settlement
except Conservation Law Foundation and the Northeast Energy
Efficiency Council agreed to accept the modifications as
presented by the Commission in its oral statement of June 26,
1998. The Amended Settlement represents significant benefits for
GSEC's customers. The Amended Settlement will bring near-term
rate relief for GSEC's customers, open GSEC's service territory
to retail choice sooner than litigation would allow, establish
transition service rates which should incent greater competition
than has materialized in either Rhode Island or Massachusetts,
establish reasonably low stranded cost charges while resolving
the stranded cost issue for GSEC, provide for low income support
consistent with our previous orders, and remove GSEC from
participation in the federal lawsuit against the Commission.
The Commission, however, notes herein that, consistent
with passage of SB 341, An Act relative to the implementation of
electric utility restructuring, which became effective July 17,
1998, approval of this Amended Settlement should not be
considered a precedent for other settlements that are presently
before us or may be forthcoming. Our approval of the Amended
Settlement is "appropriate to the particular circumstances" of
GSEC only. See RSA 374-F:3,V(d)
II. PROCEDURAL HISTORY
On February 3, 1998, Granite State Electric Company
filed with the Commission a Restructuring Settlement Agreement
relative to restructuring the electric utility industry as it
affects GSEC and its customers, that was jointly sponsored by the
Governor of the State of New Hampshire, the Campaign for
Ratepayers' Rights (CRR), Granite State Taxpayers, Inc. (GSTI),
EnerDev, Inc. (EnerDev), the Electric Utility Restructuring
Collaborative (Collaborative) with the exception of the City of
Manchester which takes no position on the Settlement,
Conservation Law Foundation (CLF), the New Hampshire Business and
Industry Association (BIA), Northeast Energy Efficiency Council,
Inc. (NEEC), Senators Frederick W. King and Leo W. Fraser, Jr.,
Representatives Clifton C. Below and Jeb E. Bradley, New England
Power Company (NEP) and Granite State Electric Company
(collectively, the Sponsors).
On February 11, 1998, the Commission issued an Order of
Notice requiring a Pre-hearing Conference to consider the issues
be held February 27, 1998; that parties wishing to intervene do
so by February 24, 1998; and that parties wishing to object to
petitions to intervene file objections by February 26, 1998.
Notice of the filing was published in the Valley News on February
12, 1998 and in the Union Leader on February 14, 1998. The
Commission received 10 timely motions for intervention and 5 late
filed motions. At the February 27, 1998 hearing, Messrs. Jim
Rodier, Esq., Sylvester Swierzy, and Pentti Aalto made oral
motions to intervene, after which the Commission granted all
petitions for intervention. (Tr. February 27, 1998, p.12) Also
at the February 27, 1998 hearing, Commission Staff, the OCA,
Cabletron Systems, Inc., Enron and RMA argued that the petitions
and the issues to be addressed in this docket and the then
pending docket, DE 97-251, regarding the transfer of New England
Power Company's generation assets to USGen New England, Inc.
(USGenNE) were so fundamentally intertwined that they could not
be addressed separately.
RMA moved orally to consolidate this docket with the
transfer docket. On March 2, 1998, the Company submitted a
Transition Service compliance filing. On March 9, 1998, GSEC
filed a draft proposed scoping stipulation that was supported by
GSTI, EnerDev, the Collaborative (excluding Manchester), BIA, and
Reps. Below and Bradley for dockets DE 97-251, the transfer
docket, and DR 98-012, the Offer of Settlement docket.
On March 10, 1998, RMA filed a written motion in
support of its February 27, 1998 oral motion, with which OCA and
Manchester concurred. On March 10, 1998, Staff filed a
memorandum in support of RMA's motion.
GSEC submitted a response on March 11, 1998, which it
characterized as a clarification of the record, reiterating its
position that consolidation was unnecessary and would not promote
the orderly and efficient conduct of either proceeding. On
March 30, 1998, the Commission issued Order No. 22,886 granting
the various motions to intervene, denying RMA's motion to
consolidate dockets DE 97-251 and DR 98-012, and accepting the
scoping stipulation filed by GSEC on March 10, 1998. In
addition, in its Order No. 22,886, the Commission approved a
procedural schedule for docket DR 98-012 and ratified the
procedural schedule for docket DE 97-251.
On May 1, 1998, the Commission, by executive letter,
directed the parties to address in legal memoranda, by May 13,
1998, the issues arising from the Companies' filing with the
Federal Energy Regulatory Commission (FERC) in which the
Companies sought and on April 28, 1998 FERC granted (New England
Power Company, Inc., 83 F.E.R.C. 61,085 (1998)) approval of an
amendment to the Companies' wholesale requirements agreement
(Granite State Amendment) to accommodate retail electric
competition. Because the Granite State Amendment includes, inter
alia, the same contract termination charges (CTC) that the
Companies requested this Commission to "review and approve," the
Commission directed the parties to set forth, in legal memoranda,
their positions regarding the Commission's jurisdiction and legal
authority to set retail stranded cost charges, to be collected by
GSEC from its retail customers, that differ from the rates, terms
and conditions of the contract termination charges approved by
the FERC.
The Commission further directed the Parties to include in
their responses a discussion of the effect on the issues raised
by the Commission's questions of the "filed rate doctrine" as
established and defined by the United States Supreme Court in,
inter alia, Nantahala Power and Light v. Thornburg, 476 U.S. 953
(1986); and Mississippi Power and Light Company v. Moore, 487
U.S. 354 (1988), and the New Hampshire Supreme Court in Appeal of
Northern Utilities, 136 N.H. 449 (1992).
Hearings were held May 26, 27, 28 and 29, 1998 and on
June 2 and 3, 1998. Post-hearing briefs were filed by the
Governor's Office of Energy and Community Services (ECS), GSEC
and NEP, CLF, Unitil, OCA, and Enron. RMA, Cabletron, James
Rodier and the Commission Staff submitted a joint brief. In
addition, post-hearing comments were submitted by Representatives
Below and Bradley and Mr. Pentti J. Aalto. In addition to the
post-hearing briefs, the extensive record includes the testimony
of the Companies' and other Sponsors' witnesses and the testimony
of the other Parties and Staff.
In a public meeting held June 26, 1998, the Commission
deliberated the Offer of Settlement and imposed certain
modifications consistent with its authority under
RSA 374-F:4,III. On June 29, 1998, the Settling Parties
submitted a response to the Commission's deliberations. Letters
were received from OCA and Cabletron, dated June 30, 1998,
opposing the response of the Settling Parties and raising
procedural questions. On July 1, 1998, the Commission issued an
executive letter stating that, after reviewing the June 29, 1998
letter and materials supplied by GSEC, the Commission determined
that the Settling Parties did not accept all of the conditions as
they were deliberated on June 26, 1998. The Commission scheduled
a hearing for July 7, 1998 to provide the Settling Parties an
opportunity to explain their filing, to answer any questions from
the Commission or any Parties about their filing, and to provide
any party with an opportunity to comment on the June 29, 1998
filing.
On July 6, 1998, Enron submitted comments and requested
that its comments be included in the record in DR 98-012. On
July 7, 1998, the Commission received a letter from GSEC
requesting a delay in the hearing scheduled for 9 a.m. that day
and withdrawing its June 29, 1998 filing. Due to the lateness of
GSEC's request, the Commission was unable to reschedule the
hearing. At the July 7, 1998 hearing, various parties indicated
that the original parties to the Settlement were still discussing
their respective positions on the Commission's Oral
Deliberations. The Commission then granted GSEC until the close
of business on July 10, 1998 to report the status of negotiations
among the settling parties.
On July 13, 1998, GSEC filed a response to the
Commission's Oral Deliberations of June 26, 1998 and letter of
July 1, 1998 stating that the Company accepted the Commission's
modifications to the Settlement. Reflecting its acceptance of
the Commission's modifications, the Company submitted a
Restructuring Settlement Agreement marked-to-show changes from
the initial Settlement Offer along with revised post-divestiture
contract termination schedules.
On July 15, 1998, the Commission issued Order No.
22,981 authorizing GSEC to reduce rates retroactive to July 1,
1998 and to proceed to implement retail choice in its service
territory based upon the modifications contained in the Amended
Settlement filed on July 13, 1998. In addition, the Commission
directed the Company to file compliance tariff pages in
conformance with Order No. 22,981. GSEC submitted its compliance
filing on July 16, 1998.
On July 22, 1998, the OCA submitted a letter
identifying certain stranded cost issues contained in the Amended
Offer of Settlement.
On August 17, 1998, the Company submitted post-divestiture revised tariff pages and requested that the
Commission issue an order authorizing GSEC to reduce its rates to
reflect the pending closing of the transfer of NEP's non-nuclear
generating assets to USGenNE which it estimated would occur on or
about September 1, 1998. On August 31, 1998, the Commission
issued Order No. 23,005 authorizing GSEC to reduce rates by an
additional 7 percent effective upon the closing of the
NEP/USGenNE asset transfer.
On October 1, 1998, the Company filed with the
Commission a copy of a Request for Qualifications to Provide
Transition Service Electricity Supply to Granite State Electric
Company (RFQ). The RFQ, which was based on the March 2, 1998
Transition Service compliance filing, modified to reflect the
timing of the auction and the term for Transition Service, was
issued by the Company to over seventy potential power suppliers.
In its transmittal letter, GSEC states that responses to the RFQ
are due November 2, 1998 and that the Company intends to conduct
the auction on December 1, 1998 for service to commence
January 1, 1999.
III. OFFER OF SETTLEMENT
Introduction
The Commission initiated Docket No. DR 96-150 to
address the requirements set forth in RSA 374-F, the State's
electric restructuring law. Following its generic investigation,
on February 28, 1997, the Commission issued Restructuring New
Hampshire's Electric Utility Industry: Final Plan (the Plan). See
Order No. 22,514. Concurrently and in accordance with RSA 374-F,
the Commission issued Order No. 22,511 specific to GSEC which,
among other things, established stranded cost charges on an
interim basis pending a final determination of GSEC's stranded
costs. See Order No. 22,511 at 15.
On March 20, 1998, the Commission issued Order No.
22,875, its Order on Requests for Rehearing, Reconsideration, and
Clarification (Order on Rehearing) in DR 96-150. The Order on
Rehearing addressed various motions for reconsideration
concerning, among other things, transition service, stranded cost
recovery, affiliate transactions and certain public policy
findings related to renewable energy and energy efficiency.
Implementation of restructuring pursuant to the Commission's
directives in Order No. 22,875 has been suspended pending ongoing
federal court action. The Settlement is intended to resolve
comprehensively and finally the electric restructuring issues for
GSEC. It also is intended to end GSEC's involvement in the
litigation in federal district court. Due to the federal
district court action and absent the voluntary Offer of
Settlement, the Commission could not compel GSEC to comply with
retail choice pursuant to the Plan or the Commission's Rehearing
Order.
Overview of the Offer of Settlement
The Offer of Settlement is comprised of the
Restructuring Settlement Agreement and seven attachments. The
complete Offer of Settlement is contained in two books. Book 1
includes the retail-related aspects of the Settlement and
includes the Restructuring Settlement Agreement and Attachment 1:
Rate Design; Attachment 3: Proposal for Environmental Component;
Attachment 4: Description of Hydro Facilities; Attachment 5:
Summary of Contracts; Attachment 6: Evaluation of FERC's Seven
Factor Test; and Attachment 7: Transition Service Framework.
Attachment 2 is contained in Book 2 and includes the Wholesale
Settlement between GSEC and NEP. Book 2 was filed at the Federal
Energy Regulatory Commission (FERC) on February 27, 1998.
GSEC states that the Offer of Settlement is consistent
with the requirements of RSA 374-F and SB 341, is substantially
consistent with the Commission's restructuring orders in Docket
No. DR 96-150 and should be approved. Brief at 2. GSEC avers
that the Settlement provides a final and comprehensive resolution
of the issues raised by electric utility restructuring in
DR 96-150. GSEC contends that, absent the Settlement, most of
the issues would remain unresolved pending the outcome of the
federal district court case in Rhode Island and subsequent
Commission proceedings. As described in the Offer of Settlement
under Section XV. Additional Provisions, if the Offer of
Settlement is not approved as filed, GSEC and the other sponsors
have reserved the right to amend voluntarily the Offer of
Settlement and refile the amended Settlement; however, GSEC
states that the sponsors may terminate the Offer of Settlement if
the Commission disapproves the Offer of Settlement in a manner
that cannot be voluntarily and consensually amended. Ex. 1 at
35, Ex. 37, Arcate at 4. If terminated, the Offer of Settlement
would be considered withdrawn and could not be used or referred
to in any other proceeding, including Docket No. DR 96-150;
however, GSEC would proceed with its May 1, 1998 compliance
filing based on the Commission's Order on Rehearing and introduce
retail choice by July 1, 1998. Ex. 37, Arcate, at 4.
The Settlement provides for customer choice to commence
in GSEC's service territory upon the closing of the sale of NEP's
non-nuclear generating assets to USGenNE or on July 1, 1998,
whichever occurs first. The Settlement also guarantees savings
to customers, establishes a transition service option for all
customers who do not choose to take electric service from a
competitive provider, provides full stranded cost recovery for
GSEC as a result of its early termination of its all-requirements
wholesale contract with NEP, accelerates funding of GSEC's share
of NEP's decommissioning costs of the Seabrook Nuclear power
plant, requires specific environmental improvements associated
with emissions from NEP's Salem Harbor and Brayton Point power
plants, makes a commitment to continued conservation programs at
current financial levels, provides support for clean, renewable
energy projects, and establishes support for low income
customers.
Description of the Offer of Settlement
I. Implementation of Retail Choice
The Settlement states that GSEC will unbundle retail
delivery tariffs to allow customers to choose their generation
supplier effective on the Retail Access Date, which is the
earlier of July 1, 1998, or the Divestiture Date. The
Divestiture Date refers to the date that NEP closes the sale to
USGenNE, or if that transaction fails, the date NEP closes the
sale, spin-off or other disposition of its non-nuclear generating
assets to a third party.
II. Stranded Cost Recovery
The Settlement provides for the final resolution of
GSEC's stranded costs due to New Hampshire electric
restructuring. On the Retail Access Date, NEP will no longer
provide GSEC with full all-requirements service as provided for
under its FERC wholesale tariff, FERC Electric Tariff, Original
Volume No. 1 (Tariff No. 1). In its place, GSEC and NEP have
agreed to an amendment to Tariff No. 1 which grants GSEC early
termination of its wholesale purchase obligations in return for a
Contract Termination Charge (CTC) paid by GSEC to NEP to
compensate NEP for the costs it incurred to serve GSEC under
Tariff No. 1 (Tariff No. 1). The Settlement provides that GSEC
will be authorized to recover in retail rates, on a fully
reconciling basis, the stranded costs as described in the CTC.
The stranded cost charges are fixed at 2.8 cents per
kWh from the Retail Access Date through December 31, 1999. The
CTC declines, thereafter, subject to adjustments. Those
adjustments, detailed in Book 2 (Ex. 1A), include a reduction for
the Residual Value Credit, and Interim Residual Value Credit, and
a risk and reward sharing mechanism. Book 2 includes post-divestiture schedules showing the effect of the closing of the
NEP/USGenNE transaction.
The Sponsors state that the stranded costs established
in the Settlement are equitable, balanced and appropriate when
viewed in the context of the Settlement. Furthermore, they aver
that the stranded costs are substantially consistent with the
policy principles for restructuring as set forth in RSA 374-F and
request that the Commission make that finding.
III. Guaranteed Savings to Customers
Upon the Retail Access Date, GSEC will provide
unbundled service which includes distribution rates as shown in
Attachment 1 of the Settlement, including a distribution
surcharge for recovery of various expenses and costs such as the
Pilot Program and a December 1996 storm, recoverable over 2
years, fully reconciling stranded cost charges, fully reconciling
transmission charges billed to GSEC from NEP, charges for
Transition Service and charges to fund energy efficiency,
renewable energy and low income programs. The Settlement
provides customers with the opportunity to receive at least 10
percent savings, on average, from their current bundled bill.
After completion of the NEP/USGenNE sale, customers' total
savings will be approximately 17 percent. Greater savings are
possible if customers procure service from competitive suppliers
at prices below Transition Service prices.
Transition Service, available to GSEC's customers of
record as of the Retail Access Date and to those new residential
and small commercial customers who request service from GSEC
within 120 days from the Retail Access Date, is intended to
provide all customers with stable prices as the competitive
electric market develops while maintaining the opportunity for
savings. Qualified suppliers for Transition Service will have
the opportunity to supply Transition Service at prices which are
at or below the Backstop prices contained in the NEP/USGenNE
agreement. Those prices are: 1998 - 3.2 cents per kWh; 1999 -
3.5 cents per kWh; 2000 - 3.8 cents per kWh; 2001 - 3.8 cents per
kWh; and 2002 (through June) - 4.2 cents per kWh. All prices
reflect flat rates for service delivered to the customer's meter
and do not include the costs for distribution, transmission or
other delivery related costs. Ex. 1, Attachment 7.
Transition Service includes a Fuel Price Index
Adjustment in the event that substantial increases in No. 6
residual fuel oil (1% S) and natural gas occur after January 1,
2000. If the Fuel Trigger Point is exceeded for any billing
month during the effective period, GSEC will pay additional
amounts to the suppliers in accordance with the formula set out
in the Fuel Price Index Adjustment. Ex. 1, Attachment 7.
From January 1, 1999, the rates for residential
Domestic Rate D customers are subject to an inflation cap
adjustment based on the Gross Domestic Product Implicit Price
Deflator using January 1, 1998 as the starting point. The
inflation cap and rates are also subject to a fuel price index
for Transition Service as set forth in Attachment 7.
IV. Default Service
Default service is available to customers who for a
period of time have left their competitive supplier and have not
begun receiving service from another or the same competitive
supplier. Default service will be provided in a manner
consistent with Commission guidelines on default service. GSEC
will fully recover any costs associated with providing default
service through a separate adjustment in rates.
V. Low Income Provisions
GSEC proposes to implement a low income program (the
Affordability Program) designed to make electric service more
affordable. The Affordability Program, which would provide low
income customers a discount off their bill, would be funded
through a wires charge. Absent adoption by the Commission of a
percentage of low income program, GSEC would file a low income
discount rate intended to provide low income customers with an
equivalent level of rate relief.
On the Retail Access Date, GSEC will provide low income
customers with a safety net service it describes as a type of
Default Service for low income customers. GSEC will
competitively procure that service. The cost of the low income
discount and power supply costs associated with the program are
recoverable through a separate adjustment in GSEC's distribution
charges billed to all customers. GSEC has also committed to the
development of a plan to back the bad debt service of low income
customers in order to reassure competitive suppliers and reduce
the potential of "redlining". The plan would be subject to
Commission review and approval.
VI. Environmental Improvements, Conservation and Renewables NEP or any successor commits to reduce air emissions of
NOx and SO2 at plants located in Massachusetts. Those plants
include Salem Harbor Units 1,2,3, and 4 and Brayton Point Units
1,2,3, and 4.
The Settlement includes a non-discriminatory, non-bypassable wires charge of 3.5 mils per kWh on average over a 5-year period effective from the Retail Access Date for DSM and
renewable energy commercialization programs. GSEC will be
allowed the opportunity to earn incentives on the DSM programs.
VII. Nuclear Decommissioning and Divestiture
NEP, a minority owner in six nuclear power plants and a
9.98 percent owner in the 1,150 MW Seabrook Nuclear power plant,
will accelerate its funding for nuclear decommissioning costs at
Seabrook Unit 1. The agreed upon accelerated funding is intended
to adequately provide a level of decommissioning funds should:
(1) Seabrook Unit 1 be retired 25 years from the commencement of
its nuclear operating license; (2) the methodology for
calculating nuclear decommissioning costs changes to reflect
nominal levelized payments; or (3) the estimated cost of
decommissioning Seabrook Unit 1 increases by up to 20 percent.
GSEC's allocated portion of the nuclear decommissioning funding
from NEP would be at least $100,000 per year.
NEP also agrees to sell, assign, lease or dispose of
its minority interest in its nuclear units and entitlements. By
July 1, 1999, NEP will file a plan with the Commission
demonstrating its best efforts to accomplish divestiture of its
nuclear entitlements. Prior to divestiture of its nuclear
assets, NEP shall implement a risk/reward sharing mechanism which
allows operating profits or costs to be apportioned to NEP at 20
percent and to GSEC's customers at 80 percent.
VIII. Divestiture of Generation Assets
On August 5, 1997, NEP agreed to sell or otherwise
transfer its ownership interest in substantially all of its non-nuclear generating assets to USGenNE. As part of the wholesale
rate settlement filed with FERC and contained in the Offer of
Settlement as Attachment 2, GSEC will receive its pro rata share
of the proceeds of the sale in the form of a Residual Value
Credit to reduce stranded costs. The Sponsors agree to support
the application of the transfer between NEP and USGenNE at the
FERC, filed on October 1, 1997, as well as NEP's filing with this
Commission in DE 97-251, and to request that the New Hampshire
Public Utilities Commission support NEP's request at the FERC and
grant NEP's petition in DE 97-251.
IX. Approval of Transfer of Hydro Facilities
Also included in DE 97-251 is NEP's petition pursuant
to RSA 374:30 to transfer its hydroelectric facilities located in
New Hampshire to USGenNE. Attachment 4 to the Offer of
Settlement describes NEP's hydroelectric facilities in New
Hampshire.
X. Market Pricing and Exempt Wholesale Generation Status
The Sponsors of this Settlement have filed with the
Commission in DE 97-251 a request that the Commission find in the
public interest that NEP or its successors or assigns, including
USGenNE, be authorized to sell power in the wholesale market. In
that request, the Sponsors also asked the Commission to find that
NEP or its successors or assigns be allowed exempt wholesale
electricity generator status pursuant to Section 32 of the Public
Utility Holding Company Act of 1935.
XI. Jurisdictional Separation Between Transmission and
Distribution
Attachment 6 of the Settlement provides an overview and
evaluation of the structure of New England Electric System, Inc.
(NEES) as it pertains to the FERC's definition of transmission
and local distribution described by FERC in its seven factor test
in Order No. 888.
XII. Marketing Affiliates
The Sponsors state that affiliates of GSEC should be
allowed to compete for the electricity, energy, and competitive
services of customers throughout New Hampshire, including those
customers in GSEC's service territory pursuant to standards of
conduct approved by the Commission. Affiliate sales will not
take place in GSEC's service territory until Commission approved
standards of conduct become effective.
XIII. Waiver of Certain Contractual Obligations
Effective on the Retail Access Date, GSEC agrees to
waive certain contract and tariff provisions in order to allow
customers with minimum notice provisions to participate in retail
competition. Those waivers pertain to customers served under
Cooperative Interruptible Service (CIS) Agreements, Service
Extension Discounts, and those nonresidential customers who have
participated in GSEC's conservation and load management programs
which require repayment of GSEC's incentives if the customer
chooses an alternative electricity provider. Additionally, the
General Service (Rate G) tariff requires all customers to provide
one year prior written notice before they may choose an
alternative power provider or install additional on-site
generation for their own use.
The Settlement does not require GSEC to waive the
advance written notice requirement needed by customers before
they may install on-site non-emergency generation for their use
or to bypass the GSEC distribution system.
If the Service Extension Discount or CIS Provisions are
not already closed, effective January 1, 1998, GSEC will close or
cease to offer those rates and incentive clauses to new
customers.
IV. POSITIONS OF NON-SIGNING PARTIES AND STAFF
A. Enron
Enron's focus in this proceeding is Transition Service
although it notes that the issues in this proceeding and in
DE 97-251 are complex and interrelated. Enron cites its
testimony and arguments concerning NEP's divestiture proposal
filed in DE 97-251 and the Commission's decision to incorporate
the record in that proceeding into the record in this proceeding.
Enron supports the Commission's policy as stated in Order No.
22,875 that a competitive bidding process should be used to
select supply resources for Transition Service.
Enron contends that true competition cannot occur if
transition service bids incorporate a price cap substantially
below market price. Brief at 2. Enron points to the Standard
Offer auctions held in Massachusetts by NEES and Commonwealth
Electric Company/Cambridge Electric Light Company as examples of
failed Standard Offer auctions. Based on those examples and the
record in this proceeding, Enron urges the Commission to reject
the proposed Settlement, including Transition Service prices
based on Exhibit 50, because it will delay true competition for
several years and does not meet the principles of RSA 374-F:2,
VII.
With respect to the response of Cabletron, RMA, James
Rodier and Staff to Exhibit 50, Enron supports much of the
material contained in that filing; however, Enron urges the
Commission to adopt the LaCapra market price projections (from
DR 96-150) or, in the alternative, to adopt Mr. McCluskey's
proposal to allow the market to determine the appropriate prices
for retail customers served under transition service.
B. OCA
The OCA urges the Commission to use Dr. Rosen's
estimate of future wholesale prices developed for this
proceeding. Ex. 22. In order to protect ratepayers from paying
more than 100% of stranded costs, the OCA states that Dr. Rosen's
bottoms-up estimate of future wholesale prices must be used
consistently for the determination of Transition Service prices,
the economics of divestiture and the calculation of stranded
costs in order to protect ratepayers from paying more than 100%
of stranded costs. Brief at 1.
Transition Service
The OCA offers three reasons why competition won't
occur by the end of the Transition Service period as proposed in
the Settlement: the stranded costs will be collected in rates,
large customers may have special pricing arrangements, and
residential customers will remain tied to a monopolistic system
that differs little from what is in place today. Brief at 2.
Dr. Rosen proposes starting with his wholesale price estimates
and adjusting them to account for additional costs necessary to
serve residential customers at retail. Brief at 4.
Dr. Rosen proposes the following retail prices which he
believes will clear the market for residential customers during
the transition period:
YEAR
Wholesale
Price
Cents/kWh
Retail Adder
Cents/kWh
Market
Price
Retail
Cent/kWh
Exhibit #55
Prices
1998
3.55
1.2
4.75
4.0
1999
3.68
1.2
4.88
4.1
2000
3.78
1.2
4.98
4.2
2001
3.90
1.2
5.10
4.3
2002
4.20
1.2
5.40
4.4
Dr. Rosen would reduce the retail adder by one-half for large
customers. The OCA points out that these prices are lower than
those used by LaCapra and adopted by the Commission in DR 96-150
when adjusted for retail.
To set the wholesale market price, Dr. Rosen proposes
an auction of the backstop supply which incorporates simultaneous
bids by up to three suppliers. Due to the minimal additional
costs incurred by these "bulk providers", the retail price would
be only slightly higher: 2 mils per kWh for large customers and 4
mils per kWh for small customers. Additional adjustments would
be needed due to the different load factors and losses of the
classes.
Stranded Costs
The OCA points out that as market price increases,
stranded cost decreases. For GSEC, the rate of the
relationship between market price and stranded cost differs
depending on whether the stranded costs are looked at in the pre-divestiture or post-divestiture case. Dr. Rosen asserts that as
the market price increases, stranded costs in the post-divestiture case increase relative to the pre-divestiture case
and remain higher. OCA contends that the market prices (both
pre-and post-divestiture) used by GSEC are too low, overstating
stranded costs by as much as $360 million post-divestiture or $11
million for GSEC's customers. Customers will have to pay for
overstated stranded costs twice: first through increased stranded
cost charges and again through higher market prices.
The OCA asserts that GSEC's customers should pay no
more than $30 million for stranded cost recovery, the pre-divestiture level of stranded costs, according to Dr. Rosen's
calculations. Dr. Rosen estimates that post-divestiture stranded
costs for GSEC are $38 million to $40 million, $17 million to $19
million less than the Settlement would allow GSEC to collect.
The OCA urges the Commission to eliminate GSEC's portion of the
mitigation incentive payment. The OCA also states that GSEC has
not acted prudently in its obligation to mitigate stranded costs
or it would not have agreed to the instant termination of its
wholesale power agreement with NEP and thus exposed its customers
to nuclear related costs as contained in the Settlement. Brief
at 13.
C. Staff
Distribution Surcharge
Mr. Cunningham recommends that the Commission approve
GSEC's Pilot Program expenses for years 1996 and 1997 and those
restructuring related costs incurred in 1997. Mr. Cunningham
would remove all 1998 costs from the Distribution Surcharge until
they are actually incurred and recorded by the Company. The 1998
costs related to the Pilot Program and restructuring would then
be recoverable, pending review by Commission auditors. Ex. 26.
Transition Service
Mr. McCluskey believes that the backstop provision in
the NEP/USGenNE sale creates benefits for GSEC's customers, but
that it is also anti-competitive. He urges the Commission to
eliminate the anti-competitive effects of the backstop provision.
Specifically, GSEC should purchase backstop power from USGenNE
whenever the winning bid, which GSEC will utilize to acquire
transition service power, is equal to or greater than the
backstop price. GSEC would then resell the power back into the
wholesale market and credit any profits against stranded costs.
Mr. McCluskey believes this adjustment would allow transition
service to function as it was intended. Customers served under
transition service would pay market-based prices for power and
all customers would benefit through the reduction in stranded
costs.
Mr. McCluskey bases his last point on the reduced sales
value of the asset transfer to USGenNE as testified to by
Mr. Levitan on behalf of Enron in the transfer docket, DE 97-251.
All customers pay more due to the lower value of the sale and
thus the higher level of stranded costs, but only transition
service customers get the benefit of the below market price of
USGenNE's backstopped prices of transition service. Mr.
McCluskey believes his amendment to the backstop provision would
remove the subsidy which flows to transition service customers
under the Offer. If the winning bid prices for transition are
below the backstop prices in the Offer, then USGenNE would
deliver any power to transition service customers.
Mr. McCluskey also comments on the effect of the
reduced sales value of the asset transfer due to USGenNE's
backstop obligations in Massachusetts and Rhode Island. He notes
that Mr. Jasanis testified in DE 97-251 that the bid submitted by
USGenNE did not provide for backstop service to GSEC, but that a
backstop option for GSEC could be purchased for approximately
$6.5 million on a present value basis. In Mr. McCluskey's view,
the additional cost of securing transition service for GSEC's
customers should be shared by all NEP's customers. GSEC's
customers, therefore, would pay no more than their allocated 3
percent share of the additional cost.
Mr. McCluskey also urges the Commission to enforce its
policy to prohibit distribution companies from administering
transition service and to eliminate the revenue loss adjustment.
The revenue loss adjustment allows NEP to sell transition service
possibly at prices below its variable costs without suffering
losses. In Mr. McCluskey's view, the revenue loss adjustment
would harm potential competitors.
Stranded Costs
Mr. McCluskey's main criticisms of the Settlement
include: the Settlement is overly generous in its recovery of
stranded costs by GSEC; the Settlement has been constructed in a
way that shifts risks to customers; certain aspects of the
Settlement are anti-competitive; and GSEC has not fulfilled its
statutory obligation to maximize its mitigation of stranded
costs.
Mr. McCluskey points out that the stranded costs in the
Settlement consist of two sets of contract termination charges
which NEP proposes to collect from GSEC. Each set of contract
termination charges includes fixed and variable components. One
set of contract termination charges is "pre-divestiture" of the
pending NEP asset sale to USGenNE. This pre-divestiture contract
termination charge is intended to recover GSEC's allocated share
of the book value of NEP's generating facilities and regulatory
assets plus GSEC's share of certain variable costs of generation
such as nuclear decommissioning, purchased power expenses, fuel
transportation expenses, employee severance and retraining costs,
and profits/losses associated with the sale of energy from NEP's
nuclear entitlements. The pre-divestiture recovery period begins
July 1, 1998. Fixed costs are recovered over 11.5 years with an
11.18 percent pretax overall return and the variable component of
the pre-divestiture contract termination charges are recovered
through 2028. Mr. McCluskey does not characterize the pre-divestiture stream of charges as stranded costs because they are
intended to recover the full book value of NEP's generating
assets without any recognition of the value of those assets.
Post-divestiture stranded costs are reduced by the
amount of GSEC's allocated share of NEP's proceeds from the non-nuclear asset sale to USGenNE. Fixed cost recovery decreases to
2 years from the pre-divesture 11.5 years and the variable cost
component continues through 2028 but at a much lower level. Mr.
McCluskey estimates that GSEC is requesting stranded cost
recovery of approximately $55 million (1998 dollars) if the sale
of NEP's non-nuclear assets closes January 1, 1999. Mr.
McCluskey points out that his $55 million estimate of stranded
cost recovery is higher than the LaCapra administrative stranded
cost estimate of $49 million that the Commission adopted as part
of its interim stranded cost charges in DR 96-150, Order
No. 22,511.
Mr. McCluskey argues that the one-time mitigation
incentive payable to NEP by GSEC of $3 million should be
rejected. The mitigation incentive fails to recognize GSEC's
continued obligation to mitigate stranded costs and, in Mr.
McCluskey's view, is not based on successful mitigation of
stranded costs.
Return on Equity
Mr. Frantz and Mr. McCluskey both filed testimony
concerning the 9.4 percent after-tax return on equity used to
calculate GSEC's portion of NEP's post-divestiture stranded
costs. Due to the provision in the Settlement which allows NEP
to adjust its contract termination charges based on changes in
sales, the cost of debt, preferred stock, capital structure or
income tax rates, Mr. Frantz believes NEP's financial risk is
essentially eliminated. Coupled with recovery of the post-divestiture fixed cost component of stranded costs over a two-year period or less, Mr. Frantz recommends that the rate of
return on equity capital should reflect some risk premium, 50 to
100 basis points, above the current yield on 2-year treasury
notes. Based on the 2-year treasury note yield of 5.5 percent,
approximately, an appropriate equity return to apply to GSEC's
post-divestiture stranded costs would be 6.0 percent to 6.5
percent. In Mr. Frantz's view, to allow a greater return would
provide a windfall to GSEC at the expense of GSEC's customers.
Mr. McCluskey also believes that NEP's business risk of
not recovering its stranded costs is virtually eliminated under
the Settlement, especially in light of the full reconciliation of
actual sales to estimated sales and the prohibition against
revisiting the justness and reasonableness of the stranded cost
charges by FERC once FERC approves them. Unlike Mr. Frantz, Mr.
McCluskey would correct for the risk-reward mismatch by
eliminating the reconciliation of revenues and stranded costs.
Nuclear Cost Issues
Mr. McCluskey opposes numerous aspects of the
Settlement related to the recovery of nuclear costs, including
the 80 percent/20 percent sharing mechanism between customers and
NEP associated with the operation of NEP's nuclear entitlements
during the period until NEP sells those assets. He believes the
mechanism favors NEP and shifts risks to customers because those
assets are more likely to suffer losses than to earn profits. He
also asserts that NEP would make a double recovery of nuclear
costs.
Public Policy Issues
Mr. McCluskey raises a number of concerns about the
Settlement's inclusion of public policy issues, especially the
funding for conservation and load management (C&LM) and nuclear
decommissioning. In particular, Mr. McCluskey states that the
Settlement provides for an average C&LM charge of 3.5 mils per
kWh for five years which equates to an annual C&LM budget of
between $2.53 million and $2.76 million. Mr. McCluskey notes
that a C&LM budget at those levels exceeds the $2 million budget
approved by the Commission for GSEC in Order No. 22,818, a level
agreed to in a settlement by the Company, CLF and Staff. He also
notes that the C&LM settlement provides for recovery of C&LM
program planning, evaluation and administration costs that were
previously recovered through GSEC Purchased Power Adjustment
Clause. Those costs are estimated at $340,000 per year. Mr.
McCluskey recommends that GSEC be ordered to comply with the
budget limitations agreed to in the settlement and approved by
the Commission in Order No. 22,875.
Mr. McCluskey urges the Commission to seek additional
comment on the Settlement's proposal to use a 25-year Seabrook
operating life for the purpose of calculating nuclear
decommissioning costs. He believes the proposed change cannot be
adopted unless the Nuclear Decommissioning Finance Committee
(NDFC) makes the same change for all joint owners of Seabrook.
V. POSITIONS OF THOSE PARTIES SPONSORING THE SETTLEMENT
A. Granite State Electric Company
The Company supports the Settlement as a final and
comprehensive resolution of the numerous issues raised by
electric restructuring. The Settlement should be viewed in its
entirety and weighed against the available alternatives: the
May 1, 1998 Compliance filing and continued state and federal
litigation. Ex. 37, Arcate at 4,5. In the Company's view, the
Compliance filing is not as favorable to customers as the
Settlement. In support of the Settlement, the Company presented
direct and rebuttal testimony on jurisdictional issues,
transition service, stranded costs, post-divestiture return on
equity, C&LM and decommissioning expenses.
B. The Governor's Office of Energy and Community Services
ECS states that the Settlement contains numerous
benefits such as (1) the opening of the retail market in New
Hampshire to competition in accordance with the time frame
mandated by statute; (2) an immediate rate reduction of 10
percent with another 7 percent to follow after divestiture; (3)
predictable, competitively priced transition service in
compliance with SB 341; (4) the end of the Company's litigation
against the Commission; and (5) a commitment to environmental
protections and public purpose programs. Brief at 1,2.
ECS states that transition service should meet the
following goals which are intended to protect consumers'
interests:
1. the option of stable and predictable generation prices
during the transition period;
2. guaranteed savings at the start of retail access for
customers who take transition service and a possibility
for additional savings from alternative competitive
suppliers;
3. equitable benefits to those who do not choose a
competitive supplier; and
4. competitive transition service prices, if possible.
Ex. 18 at 2,3.
ECS believes the transition service proposal contained
in the Settlement and as amended in Exhibit 50 meets the above
goals. ECS contends that the transition service proposal of Mr.
McCluskey does not meet those goals and that his proposal would
allow for cross-subsidization. Ex. 18 at 3. ECS states that a
competitive market takes time to develop and notes that RSA 374-F:1,II recognizes the need for a transition to a competitive
market. Brief at 8. Early market price fluctuations could be
due to a number of factors such as tight capacity, or customer
caution, or uncertainty. The backstop provision enhances a
smooth transition and shifts risks of high market prices to
USGenNE during that period and away from GSEC's customers. Tr.
Day 2 at 165 in DE 97-251. Brief at 8. ECS disputes the claims
of Mr. McCluskey and others that the proposed transition service
and the prices contained in Exhibit 50 are anti-competitive.
ECS also disputes the positions and recommendations of
Mr. McCluskey concerning C&LM. ECS states that the 3.5 mils per
kWh charge proposed in the Settlement is not an average C&LM
charge, but an average systems benefits charge to be used for
both C&LM and renewable energy related public purposes. Ex. 18
at 6. ECS avers that even if the average charge were used solely
for C&LM and increased GSEC's budget slightly, the Commission
should still approve such an outcome in the context of a global
restructuring settlement.
C. Conservation Law Foundation
CLF states that the average systems benefit charge of
3.5 mils per kWh is fully consistent with RSA 374-F, provides for
cost-effective DSM programs, provides for the possibility of
renewable energy programs, does not provide for funding in excess
of GSEC's existing budget levels for DSM, and, with the addition
of the change in transition service as contained in Exhibit 50,
should be approved in its entirety.
D. Campaign for Ratepayer's Rights
CRR supports the Settlement and states that the
Settlement represents the best chance of implementing the
policies set forth in RSA 374-F. Ex. 10 at 2. The Settlement
offers two important benefits not found in Commission Order Nos.
22,511 and 22,514: immediate rate reductions and increased and
accelerated nuclear decommissioning funding for the Seabrook
nuclear power plant. Ex. 10 at 2.
CRR rebutted Dr. Rosen's contention that the
NEP/USGenNE sale should be rejected because it resulted in a low
value which as a result insufficiently mitigated stranded costs.
Ex. 12 at 3. Dr. Rosen's position that a higher transition
charge is needed to ensure competition gets started, thereby
resulting in long-term customer savings, is opposed by CRR in
favor of immediate savings.
VI. COMMISSION ANALYSIS
As amended and filed on July 13, 1998, we find that the
Restructuring Settlement Agreement (Amended Settlement) meets the
public good standard in RSA 374:30 and is generally consistent
with the restructuring policies in RSA 374-F, recently enacted SB
341, and our previously issued restructuring orders. Although we
believe the Settlement was flawed in certain areas, our decision
to approve the Amended Settlement derives from the overall
outcome of the Amended Settlement which includes near-term rate
relief, divestiture of the majority of NEP's non-nuclear assets
resulting in reduced stranded costs and additional rate
reductions, commencement of retail choice, the end of the
Company's participation in litigation in federal district court,
an appropriate balancing of the interests of customers and
shareholders, and a transition service framework designed to
balance customer interest in stable and predictable generation
rates at the onset of retail choice without seriously restricting
the development of a competitive retail electric market. We have
evaluated the Settlement and the Amended Settlement based on the
specific requirements of RSA 374-F to determine whether the
Amended Settlement is in the "public interest." Recently enacted
SB 341 has aided our analysis. It states:
[C]ircumstances beyond the control of the public
utilities commission may delay implementation of
electric utility restructuring and consumer choice
beyond July 1, 1998. Further delay will harm the
state's economy and cause a continued burden on the
state's citizens, commerce, and industry. Delays
resulting from court orders have heightened the need to
consider negotiated settlements to expedite
restructuring, near term rate relief for customers, and
customer choice.
The Amended Settlement is a "negotiated settlement" not precluded
by the June 5, 1998 injunction by Judge Lagueux of the Federal
District Court which barred this Commission from
requiring any plaintiff, including plaintiff/
intervenors, to implement New Hampshire Revised
Statutes Annotated 374-F in accordance with the ...
Commission's orders issued in the Electric Utility
Restructuring Docket No. DR 96-150, or requiring
plaintiffs to take any action under those orders,
including the filing of compliance plans.
The restraining order clearly allowed for voluntary filings:
This order shall not preclude the defendants from
considering or ruling upon voluntary filings made by
the plaintiffs to implement New Hampshire Revised
Statutes Annotated 374-F, including the filing of
settlements or submission of compliance plans.
Unencumbered by the Federal District Court's
restraining order, we evaluated the Settlement and the Amended
Settlement based on the guidance provided us by our Legislature
and our previous decisions on restructuring. Based on those
previous decisions, we stated in our Oral Deliberations that we
could not accept certain aspects of the Settlement: those
concerning the post-divestiture equity component of stranded
costs; the term of transition service; and funding for certain
public programs related to energy efficiency and renewable
energy.
The Amended Settlement adequately addresses our
concerns and will meet the overall objectives of RSA 374-F and SB
341. We also emphasize that the high likelihood of the closure
of the NEP/USGenNE transaction reduced a number of our concerns.
Many of the issues raised by Mr. McCluskey were serious concerns
that the impending divestiture helped to resolve.
We discuss the Settlement and the Amended Settlement
below.
Jurisdiction
Before evaluating GSEC's proposed stranded cost charges
in light of the statutory standards for recovery, we note that a
disagreement exists among GSEC, the stipulating parties and
others concerning the extent of this Commission's authority and
jurisdiction to address that particular issue. According to
GSEC, we do not have the jurisdiction to set stranded cost
charges to be collected by GSEC from its retail customers that
differ from the rates, terms and conditions of the contract
termination charges approved by FERC. Staff and others point to
the FERC's decision on March 14, 1998 in Docket No. ER98-1440-000
(Central Vermont Public Service Company) and aver the opposite:
GSEC's decision to terminate its wholesale requirements
contract was not necessary to institute retail
competition pursuant to RSA 374-F...[and] any stranded
costs that NEPCo experiences as a result of the loss of
GSEC's retail customers are retail stranded costs and
are subject to this Commission's jurisdiction.
ECS observes that the Settlement was expressly structured to
leave that question open and argues that the Commission should
not waste administrative time on the issue.
We reject GSEC's claim that the Commission lacks the
jurisdiction to set GSEC's retail stranded cost charges at levels
which deviate from the stranded cost obligations voluntarily
assumed by GSEC via the CTC. As we noted in Order No. 22,986
(July 22, 1998), utilities are obligated to evaluate all cost
mitigation opportunities, including those associated with
remaining in wholesale requirements contracts versus agreeing to
the early termination of such contracts. Even though FERC
accepted the CTC filing prior to the hearing in this case, FERC's
decision does not diminish our authority (and obligation) to
evaluate GSEC's actions in light of traditional prudence
principles as well as GSEC's ongoing obligation under RSA 374-F
to take all reasonable measures to mitigate stranded costs. In
addition to the FERC's March 14, 1998 order in Docket No. ER98-1440-000, the jurisdictional demarcation was supported recently
by FERC in a decision which clarified the respective roles of
state and federal regulation in relation to wholesale purchased
power contracts. See Central Vermont Public Service Corporation,
84 FERC 61,194 (August 21, 1998).
On a related point, we reject GSEC's argument that it
was compelled to terminate its wholesale requirements contract
before retail choice could be implemented in GSEC's service
territory. GSEC appears to mistakenly assume that the existence
of wholesale contractual obligations prevents retail customers
from choosing an alternative power supplier, a notion which FERC
has rejected. Central Vermont Public Service Corporation, 81
FERC 61,336 at 62,543, n.15 (1997), order on reh'g, 84 FERC
61,295 (September 23, 1998). Not only is it possible for retail
access to co-exist with wholesale contract obligations, but such
a course may actually maximize savings for retail customers. See
e.g., New Hampshire Electric Cooperative, Inc., DR 98-097.
Stranded Costs
We are required by RSA 374-F, XII(a) to determine
whether the stranded cost recovery we approve is equitable,
appropriate, balanced and in the public interest. We must
balance the interests of customers with those of shareholders.
The Settlement provides for full and final resolution
of GSEC's stranded costs. GSEC states that its stranded costs
are due to the early termination of its wholesale all-requirements contract with NEP. Ex. 1A. The Company asks us to
focus on the post-divestiture period because it simplifies the
issues, provides significant mitigation of stranded cost
recovery, results in lower stranded cost charges in the first two
years than were reflected in the Commission's interim stranded
cost charges in DR 96-150, and substantially meets the
requirements of RSA 374-F. Brief at 7.
Others, such as Staff and the OCA, aver that stranded
costs post-divestiture provide for more than full stranded cost
recovery and do not, therefore, meet the equitable, appropriate
and balanced standard required by RSA 374-F:3, XII(a). Staff's
main concerns focus on the pre-divestiture period, but Staff
disputes the Company's claim that the sale of NEP's non-nuclear
assets reduces stranded costs by 57 percent; rejects the
Company's claim that it was ordered by the Commission to
terminate the wholesale contract; contends that GSEC failed to
defend its customers interests; criticizes various aspects
related to the recovery of costs associated with NEP's nuclear
assets; and recommend that the Commission reject or modify the
portions of the post-divestiture contract termination charges
related to return on equity and the mitigation incentive. Staff
Brief, pp. 11-20.
OCA's witness, Dr. Rosen, proposes that we use his
estimate of market prices to administratively determine the value
of stranded costs which he proposes we true-up every two years.
Tr., Day 3, pp. 52-54,69. Dr. Rosen's analysis involves
projections of revenues and costs 23 years into the future. He
calculates NEP's post-divestiture stranded costs at $360 million,
in present value dollars.
We have carefully evaluated the Company's request for
stranded cost recovery and the resulting contract termination
charges. As we stated in our Oral Deliberations, we would
approve the stranded cost portion of the Settlement if two
modifications were made. These modifications related to the
mitigation incentive and the return on equity which are addressed
later in our analysis. We also stated that, in light of recent
FERC decisions, we believe the stranded cost recovery included in
the Settlement (and the Amended Settlement) is quite favorable to
NEP. Our view has not changed. Our approval of the Amended
Settlement which adjusts stranded costs based on our Oral
Deliberations is premised on our support for market
determinations of stranded costs, not administrative ones, and
the overall level of rates resulting from the Amended Settlement,
a level we believe results in the equitable, appropriate, and
balanced requirements of RSA 374-F:4,V. Our concerns about
additional costs associated with NEP's nuclear entitlements are
addressed below.
Return on Equity
The Settlement provides NEP with the authorization to
earn an overall pre-tax return of 11.18 percent, including a
return on equity of 9.4 percent on substantially all of the
unamortized assets and balances in the contract termination
charge. Ex. 1A at 48,115. NEP's overall pre-tax return is
capped at 11.18 percent, provided that the yield on 10-year
Treasury constant maturities does not exceed 9 percent. If the
Treasury yield exceeds 9 percent, the overall return of 11.18
percent will be adjusted to include NEP's actual cost of debt and
preferred stock using a 9.4 percent equity return as described in
Ex. 1A, Appendix 2 (Post-divestiture), page 13 of 24.
GSEC and NEP support the return on equity for a number
of reasons, including that it is below: NEP's currently
authorized return on equity of 11.25 percent, GSEC's currently
authorized return on equity of 10.00 percent, the return on
equity of 10.2 percent that the Commission adopted for
distribution assets in our Rehearing Order, Order No. 22,875, and
the return on equity last approved by the Commission (Connecticut
Valley Electric Company, Docket No. DR 96-170, Order No. 22,537
(March 31, 1997)). GSEC states that the 9.4 percent return on
equity is designed to work with the incentive mechanism so when
combined they result in a return
that is consistent with traditionally allowed equity
returns only if NEP's mitigation efforts are successful
and customer savings are realized, while protecting the
financial integrity of the Company (NEP) if the sale to
USGenNE is not approved and stranded costs are not
reduced as much as we expect."
Ex. 37, Kenney at 5.
Two of Staff's witnesses argue that the formula for the
contract termination charge changes the risk allocation between
customers and shareholders because it fully reconciles revenues
and costs. Mr. Frantz points out those annual adjustments
include changes in sales, cost of debt, preferred stock, capital
structure and income taxes. Mr. Frantz states that the Company's
arguments concerning historical returns at the FERC or the equity
returns authorized by this Commission for distribution electric
companies are irrelevant to this determination. He suggests that
NEP's risk and therefore its return more closely resemble that of
short-term treasury securities. He recommends a return on equity
based on a two-year treasury bill with a risk premium of 50 to
100 basis points. Mr. McCluskey points out that customers in
California have experienced benefits of rate reduction bonds
yielding 6.5 percent with guarantees no less than contained in
the Offer of Settlement. Mr. McCluskey believes the risk-reward
mismatch could be rectified by eliminating the reconciliation of
stranded costs and revenues.
As we stated in our Oral Deliberations, we could not
accept the Settlement with the return on equity proposed by the
Sponsors in the calculation of stranded costs, post-divestiture,
given the low degree of risk and we would amend the return on
equity on New England Power Company's post-divestiture stranded
costs. Having considered all the arguments, we find convincing
Staff's testimony regarding the inappropriateness of the proposed
return on equity based on the risks NEP would face post-divestiture. We agree with Mr. Frantz that it would be
unreasonable to authorize a 9.4 percent return on equity for what
we consider to be a very low risk investment.
The Company's support for a higher return based on
previous FERC authorized returns or returns authorized by this
Commission are virtually meaningless with regard to the present
determination. The return on equity should reflect investor
risk. The record in this proceeding indicates that those risks
are more closely associated with short-term treasury bills or the
revenue reduction bond yields in California. We indicated in our
Oral Deliberations that we would adopt Mr. Frantz's
recommendation of 6.5 percent which is based on a 100 basis point
risk premium adjustment to a two-year Treasury bill. We find
that result reasonable based on the record before us.
The Amended Settlement, Appendix 2 (Post-divestiture),
reflects the change in the return on equity to the overall
capital structure. The overall pre-tax return of 8.68 percent is
used for purposes of calculating NEP's Contract Termination
Charge and is, therefore, approved by the Commission.
Mitigation Incentive Payment
In our Oral Deliberations, we stated that we would
modify that portion of the stranded cost formula in the
Settlement which allows NEP to receive a stranded cost mitigation
"incentive payment". Under this risk/reward sharing mechanism,
NEP must reduce the present value of the contract termination
charges to GSEC from $130 million to $94 million before NEP
becomes eligible for an incentive. The $130 million assumes no
mitigation. Ex. 37, Kenney, p. 5. If additional savings below
the $94 million level are achieved, NEP is allowed to retain 10
percent of those savings on stranded costs up to a cap of $3
million. The mitigation incentive payment is intended to work
with the return on equity and would increase NEP's equity return
by 1.6 percent, approximately. Ex. 37, Kenney at 4,5.
We stated in our Oral Deliberations that it would be
inappropriate for GSEC's customers to make this "incentive
payment" in light of the fact that it was negotiated after the
results of the USGenNE sale were known and GSEC's share of
stranded costs was established. We agreed with Mr. McCluskey
that an incentive payment should be linked to future cost
mitigation. The incentive proposed in the Offer of Settlement
was not. For those reasons, we could not approve a payment which
served no useful purpose and only added to the costs of GSEC's
customers unnecessarily.
GSEC has removed the mitigation incentive payment in
its Amended Settlement, a change we support for the reasons
stated above.
Transition Service
Much of the contention surrounding this proceeding
centers on Transition Service. The Settlement included a
transition period beginning on July 1, 1998 and ending June 30,
2002. Transition Service would be made available to all
customers of record as of the Retail Access Date, with additional
provisions for certain small commercial customers and all
residential customers after the Retail Access Date. GSEC will
arrange to competitively procure Transition Service and the
backstop prices of USGenNE will serve as a ceiling price for
those customers who avail themselves of Transition Service. As
contained in Attachment 7 to the Settlement, the prices are
subject to a Fuel Price Adjustment Index and residential
customers' Transition Service prices are subject to an inflation
cap.
During the proceeding, GSEC introduced into evidence as
Exhibit 50 its Proposal to Resolve Transition Service Issues.
Exhibit 50 applies to the period after divestiture only if
bidding for transition service "does not result in prices equal
to or lower than the backstop service provided by USGenNE." In
the event that competitive suppliers do not offer to provide
Transition Service at prices at or below the USGenNE backstop
prices, the Transition Service prices will include a 3 mil per
kWh adder to induce retail competition. The 3 mil adder is based
on an assumption that 100 percent of its retail customers remain
on Transition Service. The additional revenue from the 3 mil
adder will be used to offset stranded cost recovery for all
customers. If customers leave Transition Service, GSEC will not
receive the additional 3 mil adder assumed in the rate design and
will recover the resulting under-recovery from any fuel and
purchased power over-recovery remaining after divestiture.
Exhibit 50 also provides for a marketing and incentive program
funded up to $100,000 to encourage customers to leave Transition
Service if, two years after divestiture, less than 33 percent of
GSEC's total retail energy sales have moved to the competitive
market.
Staff, Enron, RMA, OCA and Aalto oppose as anti-competitive the transition service provisions of the Settlement,
particularly, the backstop provision and the term of transition
service. During the hearing, Mr. McCluskey and Dr. Rosen
described alternatives to transition service which they contend
would increase competition by eliminating or mitigating the
effects of what they believe are the below market prices of the
backstop provision. Exhibit 55, depicting an alternative to that
described in Exhibit 50, was proposed by Staff and others as a
way to minimize the anti-competitive effects of Exhibit 50.
In our Oral Deliberations, we stated that we would
accept Transition Service as contained in Exhibit 50 with some
modifications. Those modifications included a shorter transition
period and that Transition Service be made available to all
customers, not just the customers of record on the Retail Access
Date. We further stated that the prices in Exhibit 50 should
work to complement the development of the market and that the
additional 3 mil per kWh adder would not undercut the market.
Though we carefully considered the alternatives of Mr.
McCluskey and Dr. Rosen, we find that the Transition Service
proposal as filed in the Amended Settlement is consistent with
our Oral Deliberations and the requirements of RSA 374-F:3, V(b).
Transition Service in the Amended Settlement will be
competitively procured and available to all retail customers. It
will allow time for a transition to competition (RSA 374-F:1,II)
while minimizing customer confusion and providing near-term rate
relief.
The record clearly indicates a lack of competition,
thus far, in Massachusetts and Rhode Island. A long transition
period coupled with low, perhaps below market, prices is no
prescription for competition. We are only too aware that the
Transition Service of the Amended Settlement strays from our
guidelines on Transition Service in our Rehearing Order, but we
believe that Exhibit 50 provides a fair compromise between
stable and predictable rates and the development of the market if
transition service bids fail to materialize. Our ability to re-evaluate the market in the near future and determine whether to
extend or terminate Transition Service on December 31, 2000,
allays our concerns about the potentially below-market prices of
the backstop provision.
The prices contained in Exhibit 55 would simply
increase rates to customers who are not yet ready to make that
choice. We share the concerns of Mr. McCluskey and Dr. Rosen
about the potentially anti-competitive effects of the backstop
provision, and note that there is evidence in the record upon
which to base those concerns. However, we are persuaded that the
3 mil per kWh adder contained in Exhibit 50 and our ability to
re-evaluate the level of competition in the near future somewhat
mitigate those concerns. Finally, the staggered pace at which
competition is occurring in New Hampshire provides some
additional rationale that the Amended Settlement's Transition
Service will offer customers some benefits without greatly
compromising the benefits of competition.
Nuclear Costs
NEP has indicated it will divest its nuclear assets,
but that it is not in the customer's interest to do so at this
time. Under the Settlement, all past investment, post-shutdown,
and nuclear decommissioning costs are fully recoverable through
the contract termination charge. Ex. 37, Kenney at 13. Until NEP
can transfer its nuclear assets, NEP will implement a
performance-based ratemaking (PBR) mechanism for its nuclear
operating units. Under the nuclear PBR, NEP agrees to assume 20
percent of the incremental costs, including capital costs, and
the revenues as part of its performance-based ratemaking
mechanism. The remaining 80 percent will be assumed by the
retail customers of NEP's affiliated distribution companies. Other parties, including Staff's Mr. McCluskey, oppose
the nuclear PBR mechanism on the grounds that it shifts the
operating risks of nuclear plants to customers and that the
nuclear plants are more likely to lose money than to earn
profits. Ex. 29, p. 22,25. NEP disagrees. Ex. 37, Kenney, p.
15. NEP projects early year operating losses will be offset by
profitable operations in later years. In addition, the Company
disagrees with other aspects of Mr. McCluskey's testimony,
including his assertion that NEP will double recover certain
nuclear costs. Ex. 37, Kenney, p. 14.
We have carefully reviewed the nuclear cost issues and
find that the circumstances of NEP's nuclear ownership are
central to our approval of this segment of the Amended
Settlement. NEP's minority interest does not excuse it from
taking all appropriate actions to minimize nuclear operating
costs while ensuring safe plant operations. The customers of
GSEC should expect no less. Nonetheless, small percentage
ownership interests do affect a utility's ability to make
significant operating or managerial changes. We recognize this
fact and we recognize NEP's commitment to sell its nuclear
assets. Ex. 1A, pp.16-19. We will expect NEP to pursue
aggressively a nuclear divestiture plan that maximizes, in a
timely manner, stranded cost reduction. Our review of NEP's sale
of its nuclear assets will include a review of stranded costs
consistent with the provisions of RSA 374-F:3,XII.
Until that divestiture occurs, we find the 80
percent/20 percent sharing mechanism a reasonable way to share
the operating risks and benefits of NEP's nuclear entitlements.
If NEP does not sell off its nuclear entitlements within a
reasonable period of time, however, we will re-evaluate the PBR
mechanism.
This is an area in the Settlement that clearly poses
potential risks to customers. We are aware that a proceeding
before FERC is on-going concerning the recovery of certain costs
associated with the early closure of Connecticut Yankee. We will
direct the Company to file a letter with this Commission
indicating how it will respond if certain disallowances are made
to the recovery of nuclear post-shutdown or replacement power
costs based on an imprudence finding by FERC for those units in
which NEP has a minority interest. We do not expect the Company
to pass on costs found imprudent to its customers.
Nuclear Decommissioning
We believe it is appropriate to accelerate funding of
NEP's portion of the expected Seabrook Unit 1 decommissioning
expenses based on an assumed closure date of midyear 2015. We
recognize that sufficient nuclear decommissioning funding is
highly dependent upon on a number of variables, including the
type and age of plant, but we find the Settlement compelling and
timely in regard to this issue as it pertains to NEP and GSEC's
share of NEP's decommissioning costs.
The Amended Settlement also includes, through the
contract termination charge, the recovery of post-shutdown and
nuclear decommissioning costs associated with NEP's minority
interests in the following closed nuclear plants: Yankee Atomic,
Maine Yankee, and Connecticut Yankee. The Company supports these
cost recoveries because closure of the plants was in the economic
interest of customers. The Company states that the expected
shutdown costs are now even less than when the decision was made
and that customers will receive any reductions in actual costs
through the Reconciliation Account. NEP owns minority interests
in three other nuclear plants that are currently operating:
Seabrook, Millstone 3 and Vermont Yankee.
Public Policy Issues
The Settlement contained a number of concerns related
to energy efficiency and environmental issues upon which we had
previously provided policy guidance. In particular, our March
20, 1998, Rehearing Order reversed our directive that utilities
phase-out their DSM programs over a two-year period. We were
persuaded instead to grant the request of some of the parties in
DR 96-150 to convene a working group to address many of the
complex issues concerning DSM or energy efficiency in a
restructured electric environment. Some of those same parties
now would have us ignore our directives on rehearing or at least
those with which they disagree. Specifically, they seek through
the Settlement a level of funding on average of 3.5 mils per kWh
over a five-year period for energy efficiency programs and a
renewable energy commercialization initiative, an initiative that
could only be characterized as conceptual at this time.
We heard no compelling arguments to change our position
as articulated in Order No. 22,875. As we stated in our Oral
Deliberations, we could not accept this part of the Settlement
and would require that any changes to the Settlement reflect our
previous decisions concerning energy efficiency and renewables.
The Amended Settlement meets those criteria.
Other Issues
Competitive Supplier Registration
In the Plan, we established a rulemaking proceeding to
address registration requirements for competitive suppliers of
electric services. Although initiated, the final supplier
registration rules are not complete and we do not envision that
these rules will be finalized and issued in the very near future.
Consequently, we have outlined temporary registration procedures
in Attachment 1 of this order specifically for those suppliers
selling in GSEC's franchise area.
The temporary procedures which we establish today also
include consumer protection requirements with which competitive
suppliers must comply. While there are already several suppliers
registered to sell to Retail Competition Pilot Program
participants, the procedures being adopted in this Order differ
significantly from those adopted in the Pilot Program. Any Pilot
Program supplier who wishes to provide competitive electric
energy services to Granite State customers must re-register with
the Commission before it can begin to market and sell to
customers in GSEC's franchise area.
In addition, we also attach the interim affiliate
transaction guidelines which must be followed by GSEC and any
affiliate selling unbundled electric energy products or services
in GSEC's franchise territory. As with the interim procedures
governing supplier registration and consumer protection, these
guidelines shall apply to GSEC and its affiliates in GSEC's
service territory until final rules are issued.
Consistent with our decision on the New Hampshire
Electric Cooperative's Electric Restructuring Settlement, an
affiliate of a retail electric company which has not received
approval from this Commission for its compliance filing or
settlement may not participate in the retail market of GSEC. See
Order No. 23,013 in DR 98-097 (September 8, 1998). See also RSA
374-F:4, IX.
Low Income Energy Assistance
In the Plan, we approved a level of funding for a low
income energy assistance program and initiated the formation of a
working group to assist us in the development of such a program.
The working group submitted its final report to the Commission on
August 28, 1998. The working group has recommended that until
the Commission issues rules for a consistent statewide low income
assistance program, the Commission consider and adopt, on a case
by case basis, modified programs as may be proposed by individual
utilities.
In the Amended Settlement, GSEC agreed to file a low
income discount rate in substitution of the percentage of income
payment program being developed by the working group should that
program not be approved and available at the time Granite State
implements retail choice. We remain committed to the development
of a low income assistance program. We believe that it will be
less confusing to customers to see the systems benefit charge for
such a program begin simultaneously with the implementation of
retail choice than to see it as a new charge on their bill
several months from now. Consequently, we accept the Company's
proposal and authorize it to begin collecting a systems benefit
charge of 1.5 mils per kWh to fund a low income affordability
credit with the understanding that the credit will be terminated
once the Commission approves a statewide low income assistance
program and the program is implemented. We expect the Company to
submit a filing for the interim affordability program for our
review and approval before placing it into effect. We will not
authorize GSEC to provide a "safety net service" as a type of
Default Service for low income customers as described in Section
V, Low Income Protections. We believe the prices contained in
Transition Service coupled with the low income affordability
program will provide those necessary protections. We are
concerned by GSEC's commitment to back the bad debt service for
competitive electric suppliers of low income customers. However,
we will review any plan which is submitted.
Electronic Data Interchange
We remind GSEC and potential electric suppliers that
the report from the Electronic Data Interchange (EDI) working
group will form the basis for EDI transactions until the EDI
rulemaking is complete. GSEC should also note that it must
complete its EDI testing before it can test potential suppliers.
When GSEC has completed its own testing, it should inform the
Commission. GSEC should also inform the Commission when electric
suppliers have met the EDI requirements.
Based upon the foregoing, it is hereby
ORDERED, that the Amended Restructuring Settlement
Agreement as filed by Granite State Electric Company and
supported by the joint sponsors on July 13, 1998, is APPROVED
consistent with the analysis set forth above; and it is
FURTHER ORDERED, that the attachments to this order for
supplier registration and affiliate transactions are adopted
specifically as they apply to GSEC and its customers until such
time that the Commission orders otherwise; and it is
FURTHER ORDERED, that GSEC's bills reflect unbundled
tariff elements as shown in Attachment 1 to the Offer Of
Settlement which shall include separate line items for the
following: Customer Charge, Distribution, Transmission, Stranded
Cost Charge, Distribution Surcharge, Low Income Charge,
Conservation and Load Management, and a Generation Charge
reflecting either the transition service generation charge or the
competitive generation charge, if appropriate; and it is
FURTHER ORDERED, that a docket be opened within the
next 30 days to address the transmission issues raised by Mr.
Rodier.
By order of the Public Utilities Commission of New
Hampshire this seventh day of October, 1998.
Douglas L. Patch Bruce B. Ellsworth Susan S. Geiger
Chairman Commissioner Commissioner
Attested by:
Thomas B. Getz
Executive Director and Secretary
ATTACHMENT 1
DR 98-012
INTERIM PROCEDURES ESTABLISHING REGISTRATION
REQUIREMENTS FOR COMPETITIVE ENERGY SUPPLIERS
SERVING RETAIL CUSTOMERS OF GRANITE STATE ELECTRIC COMPANY
Chapter Puc 2000 COMPETITIVE ENERGY SUPPLIER RULES
Adopt Puc 2000 to read as follows:
PART Puc 2001 PURPOSE AND APPLICATION OF RULES
Puc 2001.01 Purpose.
(a) The purpose of Puc 2000 is to establish requirements for
competitive energy suppliers consistent with the promotion of full and
fair competition among competitive energy suppliers.
(b) Competitive energy suppliers shall:
(1) Demonstrate a minimum level of financial resources and
the ability to provide customers with the level of service
they agree to purchase;
(2) Engage in fair business practices and comply with all
applicable consumer protection laws and rules;
(3) Disclose, and make available to the public, information
that will enable customers to make informed choices
regarding the supply of their power; and
(4) Demonstrate they have qualified to do business and are
subject to service of process in New Hampshire.
Puc 2001.02 Application of Rules. Competitive energy suppliers
and aggregators shall comply with Puc 2000.
PART Puc 2002 DEFINITIONS
Puc 2002.01 "Aggregate" means to combine the loads of multiple
customers.
Puc 2002.02 "Aggregator" means any entity who aggregates
electricity load and does not take ownership of the energy supplies
needed to meet that aggregated load.
Puc 2002.03 "Commission" means the New Hampshire public
utilities commission.
Puc 2002.04 "Competitive energy supplier" means any entity who
sells or offers to sell electric energy service to retail customers.
Puc 2002.05 "Electricity supply offer" means a solicitation to
provide electric energy service tendered by a competitive energy
supplier to a customer.
Puc 2002.06 "Customer" means any person, firm, partnership,
corporation, cooperative marketing association, tenant, governmental
unit, or a subdivision of a municipality, or the state of New
Hampshire who purchases retail electric generation supply from a
competitive energy supplier.
Puc 2002.07 "Established business relationship" means an existing
relationship formed by a voluntary two-way communication between a
competitive energy supplier and a residential or non-residential
customer, with or without an exchange of consideration, on the basis
of an inquiry, application, purchase, or transaction by the
residential customer regarding products or services offered by the
competitive energy supplier or aggregator.
Puc 2002.08 "Small commercial customer" means any non-residential
customer whose known or estimated maximum demand is less than or equal
to 100 kilowatts.
Puc 2002.09 "Telephone solicitation" means the initiation of a
telephone call or message for the purpose of encouraging the purchase
of a product or service, unless the call is made with the customer's
express invitation or permission and the customer has an established
business relationship with the caller.
PART Puc 2003 REGISTRATION REQUIREMENTS
Puc 2003.01 Procedure for Registration.
(a) All competitive energy suppliers seeking to sell electric
energy to retail customers in the state of New Hampshire shall file a
registration application with the commission.
(b) The registration application required by (a) above shall
include, at a minimum, the following:
(1) The legal name of the applicant as well as any trade
name(s) they intend to operate under;
(2) The applicant's New Hampshire business address and
principal place of business;
(3) The names and business addresses of the applicant's
principal officers;
(4) The names of the applicant's affiliates and
subsidiaries;
(5) Disclosure of any affiliate relationships and the nature
of any affiliate agreements with New Hampshire
jurisdictional electric distribution companies;
(6) Telephone number of the customer service department or
the name, title and telephone number of the customer service
contact person;
(7) Name, title and telephone number of the regulatory
contact person;
(8) Name, title and telephone number of the registered agent
in New Hampshire for service of process;
(9) A copy of the applicant's authorization to do business
in New Hampshire from the secretary of state;
(10) Certification of compliance with independent system
operator reliability requirements;
(11) Evidence of a minimum level of financial resources in
the name of the applicant and available for the New
Hampshire expenses of the applicant, on deposit in a New
Hampshire bank or financial institution, in an amount not
less than $20,000, in the form of:
a. Cash; or
b. A financial instrument showing evidence of liquid
funds, such as a certificate of deposit, an
irrevocable letter of credit, a line of credit, a loan
or a guarantee.
(12) A listing and explanation of any proceedings where the
applicant or any of its principals, in the conduct of its
business within the past 5 years, have been or are currently
the subject of state or federal investigation or have had
its authority to do business revoked;
(13) Affidavit that the applicant agrees to comply with the
consumer protection requirements set forth in Puc 2004;
(14) Verification of successful implementation of electronic
transaction capability with New Hampshire distribution
companies; and
(15) Affidavit that the applicant:
a. Will obtain and maintain lists of consumers who
have requested being placed on a do-not-call list for
the purposes of telemarketing, including telephone
preference services lists maintained by the Direct
Marketing Association;
b. Will not initiate calls to New Hampshire customers
who have requested being placed on do-not-call lists
and/or customers who are listed on the Direct
Marketing Association's telephone preference lists;
and
c. Will obtain updated lists from the Direct
Marketing Association no less than semi-annually.
(b) A $500 registration fee shall accompany each initial
application.
(c) Competitive electric suppliers shall re-register with the
commission annually.
(d) Competitive electric suppliers shall submit to the commission
the annual re-registration fee of $250.
(d) Based on a review of the completeness of the information
provided in (a) above and the applicant's ability to demonstrate
compliance with the requirements of Puc 2001.01(b), the commission
shall make a determination regarding certification of an applicant's
registration within 30 days of receipt of the application.
(e) Should the commission fail to make a determination within 30
days of receipt of the application, the applicant shall be certified
to provide electric generation supply until the commission completes
its review.
(f) If after the commission completes its review it finds that
the application is not complete or the applicant failed to demonstrate
an ability to comply with requirements of Puc 2001.01 (b), the
certification to provide electric generation supply shall, once the
commission complies with RSA 541-A:29, be revoked.
(g) Any entity seeking to provide aggregation service to retail
customers shall provide notification to the commission of their intent
to do so.
(h) The notice of intent, required by (g) above, shall include,
at a minimum, the following:
(1) The legal name of the aggregator as well as any trade
name(s) they intend to operate under;
(2) The aggregator's business address and principal place of
business;
(3) The names and addresses of the aggregator's principal
officers;
(4) The telephone number of the customer service contact
person; and
(5) A copy of the aggregator's authorization to do business
in New Hampshire from the secretary of state.
PART Puc 2004 CONSUMER PROTECTION REQUIREMENTS
Puc 2004.01 Transfer of Service.
(a) Each competitive energy supplier seeking to provide a
customer with electric energy service shall obtain valid authorization
from the customer before providing such service.
(b) Valid authorization, as described in (a) above, shall
include written, verbal, faxed or electronic authorization.
(c) Verbal authorization, pursuant to (b) above, must be
verified by an independent third party for the authorization to be
deemed valid.
(d) When a customer's request for a change in competitive energy
suppliers is received over the telephone, the competitive energy
supplier shall mail an information package to the customer within
three working days of the customer's request.
(e) The information package, described in (d) above, shall
include:
(1) A statement that the information is being sent to
confirm the telemarketing order or verbal request;
(2) The name, address and telephone number of the newly-requested competitive energy supplier;
(3) The disclosure statement described in Puc 2004.02; and
(f) The written authorization form, required by (b) above, shall
contain, at a minimum, the following:
(1) The customer's billing name and address;
(2) The account number(s) to be covered by the request for
change in competitive energy suppliers;
(3) A statement that the customer has not initiated another
change in competitive energy suppliers within the current
billing period; and
(4) The customer's signature.
(g) The authorization form shall be clearly identifiable and
separate from any other marketing materials.
(h) Upon receipt of valid authorization from the customer, the
competitive energy supplier shall notify the distribution company
electronically of the customer's request to switch competitive energy
suppliers.
(i) Competitive energy suppliers shall provide the distribution
company with proof of valid authorization whenever requested by the
distribution company.
(j) The competitive energy supplier shall maintain records of
authorization to switch service for a period of one year.
Puc 2004.02 Electricity Supply Offer Disclosure Requirements.
(a) The competitive energy supplier shall, prior to acceptance
of any written or verbal electricity supply offer, provide the
customer a disclosure statement.
(b) The disclosure statement required by (a) above shall contain,
at a minimum, the following
information:
(1) All fixed and variable prices of the service being
offered including any penalties or fees for:
a. Late payments;
b. Early termination of the electricity supply
agreement by the customer; or
c. Any other penalties or fees.
(2) The term of the competitive energy supplier's commitment
for price and terms and conditions;
(3) The term of the customer's commitment to purchase from
the competitive energy supplier;
(4) A description of the competitive energy supplier's
dispute resolution process available to the customer if
dissatisfied with the service;
(5) An explanation of how the customer will be billed for
generation service and the name and address of the
competitive energy supplier's billing agent, if any;
(6) The competitive energy supplier's policy regarding
disclosure of customer usage, billing and payment
information; and
(7) The commission's toll free consumer affairs telephone
number and a statement that customers may contact the
commission if they have any questions about their rights and
responsibilities.
(b) When the electricity supply offer is made to the customer as
part of a telephone solicitation, the competitive energy supplier, or
its representative, shall disclose all of the information required in
(b) above orally to the customer prior to the customer's acceptance of
the offer in addition to providing written disclosure as required in
(b) above.
Puc 2004.03 Bill Disclosure Information.
(a) The competitive energy supplier shall include on any bills
which it issues or which are issued on its behalf, the following
information:
(1) The starting and ending date of the billing period;
(2) Any fixed monthly charges;
(3) The price structure for kilowatt hour use;
(4) The prior meter reading;
(5) The current meter reading;
(6) The total kilowatt hours used during the billing period
which shall include for customers on a time-of-use or
similar pricing schedule, the total kilowatt hours used
broken down by time of use;
(7) Any applicable penalty date and the related penalty;
(8) Any other factors necessary to compute the charges;
(9) An itemized breakdown of the charges, including any late
fee, penalty or aggregation fee if applicable;
(10) The average price per kilowatt hour used during that
billing period;
(11) A statement that the customer has the right to request
actual consumption information for each billing period
during the prior year or the months therein during which the
competitive energy supplier provided the customer with
generation service;
(12) The telephone number of the supplier's customer service
department or customer service contact person; and
(13) The toll free telephone number of the commission's
consumer affairs division.
(b) Upon request of a customer, competitive energy suppliers
shall provide the customer with a clear and concise statement of the
customer's actual consumption for each billing period during the prior
year or the months therein which the competitive energy supplier
provided the customer with generation service.
Puc 2004.04 Notice of Termination of Service.
(a) Competitive energy suppliers shall provide 10 working days
written notice to residential and small commercial customers prior to
terminating the provision of generation service when the customer has
failed to meet any of the terms of the agreement for service.
(b) Termination of service, which shall follow the notice period
referred to in (a) above, shall be deferred until the later of the
next meter reading date or the termination date specified on the
notice to the customer.
(c) Competitive energy suppliers shall provide 5 working days
written notice to customers whose maximum demand exceeds 100 kilowatts
prior to terminating the provision of generation service when the
customer has failed to meet any of the terms of the agreement for
service.
(d) Competitive energy suppliers shall provide 2 working days
electronic notice to the distribution company prior to terminating the
provision of service to any customer who has failed to meet the terms
of the agreement for service.
(e) While no authorization is required from the commission,
competitive energy suppliers who decide to cease providing generation
service within the state shall, prior to discontinuing service:
(1) Provide sufficient electronic notice, which for the
purposes of this paragraph means the later of the starting
date of the next billing cycle or 30 calendar days from the
delivery of notice, to the distribution companies and
written notice to customers of the supplier's intent to
cease operations; and
(2) Refund any outstanding customer deposits.
Puc 2004.05 Telephone Solicitation.
(a) No competitive energy supplier shall initiate any telephone
call using an automatic telephone dialing system or an artificial or
prerecorded voice unless the call is initiated for emergency purposes
which, for the purposes of this section, shall be defined to mean any
situation affecting the health and safety of customers.
(b) No competitive energy supplier shall initiate any telephone
call to any of the following:
(1) An emergency telephone line, including any 911 line or
any emergency line of a hospital, medical physician or
service office, health care facility, poison control center,
or fire protection or law enforcement agency; or
(2) The telephone line of any guest room or patient room of
a hospital, health care facility, elderly home, or similar
type establishment; or
(3) A telephone number assigned to a paging service,
cellular telephone service, specialized mobile radio
service, or other radio common carrier service, or any
service for which the called party is charged for the call.
(c) No competitive energy supplier shall use a telephone
facsimile machine, computer, or other device to send an unsolicited
advertisement to a telephone facsimile machine.
(d) No competitive energy supplier shall initiate any telephone
solicitation to a customer before 8:00 a.m or after 9:00 pm eastern
time.
(e) The called party shall be provided with the name of the
competitive energy supplier on whose behalf the call is being made as
well as a telephone number or address at which the competitive energy
supplier can be reached..
(f) No competitive energy supplier shall initiate any telephone
solicitation to a customer unless the competitive energy supplier has
instituted procedures, as provided below, for maintaining a list of
persons who do not wish to receive telephone solicitations made by or
on behalf of that competitive energy supplier.
(g) A competitive energy supplier shall implement procedures for
telephone solicitation including:
(1) The competitive energy supplier must maintain a written
policy for maintaining a do-not-call list and make such
policy available to customers upon request;
(2) Personnel engaged in any aspect of telephone
solicitation must be informed and trained in the existence
and use of the do-not-call list;
(3) If a residential customer makes a request to be placed
on the do-not-call list, the request must be recorded at the
time it is made;
(4) To protect the customer's privacy, the competitive
energy supplier must obtain prior express consent from the
customer before the customer's request to be placed on a
do-not-call list can be shared with or forwarded to a party
other than the competitive energy supplier on whose behalf
the solicitation is being made; and
(5) Competitive energy suppliers must maintain do-not-call
lists for the purpose of any future telephone solicitations
and shall not contact customers on this list.
(g) All competitive energy suppliers shall:
(1) Contact the Direct Marketing Association's Telephone
Preference Service and obtain a listing of New Hampshire
customers who have registered with that service prior to
conducting any telephone solicitations;
(2) Update its lists semi-annually from the Direct
Marketing Association's Telephone Preference Service
listings; and
(3) Not make telephone solicitations to any customer who
has registered with that service or requested do-not-call
treatment.
(h) All competitive energy suppliers shall
PART Puc 2005 DISPUTE RESOLUTION PROCEDURES
Puc 2005.01 Investigation by the Commission.
(a) When a customer files a complaint with the commission's
consumer affairs division, either orally or in writing, against a
supplier alleging that the competitive energy supplier is not in
compliance with the provisions of Puc 2000, the commission's consumer
affairs division shall be authorized to begin an informal
investigation.
(b) The competitive energy supplier shall provide any relevant
information to the consumer assistance department which would assist
the consumer assistance department in its efforts to investigate and
resolve the dispute.
(c) If a competitive energy supplier feels the complaint does not
constitute on its face a violation of Puc 2000 or applicable statues
or administrative law, it may request a hearing before the
commission.
(d) If the commission determines the complaint on its face is
warranted, the competitive energy supplier shall be required to
provide any relevant information to the consumer affairs division
which would assist it in its efforts to investigate and resolve the
dispute.
(e) The competitive energy supplier or the customer may request a
hearing before the commission if dissatisfied with the resolution of
the complaint.
(f) The consumer affairs division shall request a hearing before
the commission when it determines issues remain which require
resolution by the commission.
(g) Any information provided by the competitive energy supplier
which the competitive energy supplier attests is commercially
sensitive and meets one of the criteria for confidential information
set forth in Puc 204.08(b) shall be treated confidentially in
accordance with Puc 204.08(c).
(h) During a two year interim period which begins on the date
that competition is implemented in one or more areas of the state, the
commission shall also mediate and resolve disputes which are outside
the purview of Part Puc 2003 and 2004.
(i) The commission shall, pursuant to RSA 374-F:9,III, fine a
competitive energy supplier for any of the following:
(1) Failure to register with the commission as required in
Puc 2003.01;
(2) A violation of any one of the provisions of Puc 2004; or
(3) Any similar circumstances consistent with (1) and (2)
above..
(j) The commission shall, pursuant to RSA 374-F:9,III, revoke a
competitive energy supplier's registration for:
(1) Willful misrepresentation of any of the information
required by 2003.01;
(2) Repeated violations of any one of the provisions of Part
2004;
(3) Widespread systematic market abuses which violate any
of the provisions of Part Puc 2004; or
(4) Any similar circumstances consistent with (1) through
(3) above..
ATTACHMENT 2
DR 98-012
INTERIM PROCEDURES GOVERNING TRANSACTIONS BETWEEN
GRANITE STATE ELECTRIC COMPANY AND AFFILIATED COMPANIES
PART Puc 2101 DEFINITIONS
Puc 2101.01 "Affiliate" means any person, corporation, utility, partnership, or other entity 5
per cent or more of whose outstanding securities are owned, controlled, or held with power
to vote, directly or indirectly either by a utility or any of its subsidiaries, or by that utility's
controlling corporation and/or any of its subsidiaries as well as any company in which the
utility, its controlling corporation, or any of the utility's affiliates exert substantial control
over the operation of the company and/or indirectly have substantial financial interests in
the company exercised through means other than ownership.
Puc 2101.02 "Commission" means the New Hampshire Public Utilities Commission.
Puc 2101.03 "Customer" means any person or corporation that is the ultimate consumer of
goods and services.
Puc 2101.04 "Customer information" means non-public information and data specific to a
utility customer which the utility acquired or developed in the course of its provision of
utility services.
Puc 2101.05 "FERC" means the Federal Energy Regulatory Commission.
Puc 2101.06 "Fully Loaded Cost" means the direct cost of a good or service plus all
applicable indirect charges and overheads.
Puc 2101.07 "Subsidiary" means a company or entity owned and controlled by a utility, the
revenues and expenses of which are subject to regulation by the Commission and are
included by the Commission in establishing rates for the utility.
Puc 2101.08 "Utility" means any public utility as defined in RSA 362:2 which provides or is
involved in the provision of electric service ultimately sold to the public or competitive
electric suppliers.
PART Puc 2101 APPLICABILITY OF RULES
Puc 2102.01 Applicability of Rules.
(a) Puc 2100 shall apply to:
(1) Public utilities, as defined in RSA 362:2, which provide electrical
services;
(2) Affiliated competitive suppliers;
(3) All utility transactions with affiliates that provide a product that uses
electricity or provides services that relate to the use of electricity, unless
specifically exempted; and
(4) Transactions between a Commission-regulated utility and another
affiliated utility, unless specifically modified by the Commission in addressing a
separate application to merge or otherwise conduct joint ventures related to
regulated services.
(b) Existing Commission rules for each utility and its parent holding company shall
continue to apply except to the extent they conflict with Puc 2100, in which cases Puc 2100 shall
supersede prior rules.
(c) Nothing in this chapter shall preclude:
(1) The Commission from adopting other utility-specific guidelines; or
(2) A utility or its parent holding company from adopting other utility-specific
guidelines, with advance Commission approval.
Puc 2102.02 Affiliate Entities and Transactions Described.
(a) "Substantial control", as used in the definition of affiliate in Puc 2101.01, shall
include, but shall not be limited to, the possession, directly or indirectly and whether acting alone
or in conjunction with others, of the authority to direct or cause the direction of the management
or policies of a company.
(b) A direct or indirect voting interest of 5% or more by the utility in an entity's
company shall create a rebuttable presumption of substantial control sufficient to characterize the
company as an affiliate of the utility.
(c) For purposes of Puc 2100, "affiliate" shall include the utility's parent or holding
company, or any company which directly or indirectly owns, controls, or holds the power to vote
10% or more of the outstanding voting securities of a utility or its holding company, to the extent
the holding company is engaged in the provision of products or services as described in Puc
2100.03(b).
(d) In its compliance plan filed pursuant to Puc 2106, the utility shall demonstrate
both the specific mechanism and procedures that the utility and holding company have in place
to assure that the utility is not utilizing the holding company or any of its affiliates not covered
by Puc 2100 as a conduit to circumvent Puc 2100 in any manner, including but not limited to
those described in (e) below.
(e) The utility shall demonstrate in its compliance plan, as described in (d) above,
specific mechanisms and procedures to assure the Commission that the utility will not use the
holding company or any another utility affiliate not covered by Puc 2106 as a vehicle to:
(1) Disseminate information transferred to them by the utility to an affiliate
covered by Puc 2100 in contravention of Puc 2100;
(2) Provide services to its affiliates covered by Puc 2100 in contravention of
Puc 2100; or
(3) Transfer employees to its affiliates covered by Puc 2100 in contravention
of Puc 2100.
(f) In the compliance plan, a corporate officer from the utility and holding company
shall verify the adequacy of the specific mechanisms and procedures described in the compliance
plan to ensure that the utility is not utilizing the holding company or any of its affiliates not
covered by Puc 2100 as a conduit to circumvent Puc 2100 in any manner.
(g) Subsidiaries of a utility are not included within the definition of affiliate.
(h) Puc 2100 shall apply to all interactions any regulated subsidiary has with other
affiliated entities covered by Puc 2100.
(i) Puc 2100 shall not preclude or stay any form of civil relief, or rights or defenses
thereto, that may be available under state or federal law.
(j) A Commission-jurisdictional utility may apply to be exempt from Puc 2100 by
filing a written request with the Commission requesting exemption as provided in (k) and (l)
below.
(k) The utility shall file its request for exemption from this part as follows:
(1) The utility shall file the letter within 30 days after the effective date of Puc
2100; and
(2) The utility shall simultaneously serve a copy of its letter on all members of
the service list of this rulemaking proceeding.
(l) The utility shall, in its written request pursuant to (g) above,:
(1) Attest that no affiliate of the utility provides services as described in Puc
2102.01(a)(3) above; and
(2) Attest that if an affiliate is subsequently created which provides services as
described in Puc 2102.01(a)(3), then the utility shall:
a. Notify the Commission, by means of a letter to the executive
director and secretary with a copy served on all parties to this rulemaking
docket, at least 30 days before the affiliate begins to provide services as
described in Puc 2102.01(a)(3), giving notice that such an affiliate has
been created; and
b. Include in this notice an affirmation by the affiliate agreeing to
comply with all applicable Commission rules.
(m) A New Hampshire utility which is also a multi-state utility and which is subject to
the jurisdiction of other state regulatory commissions, may file with the Commission an
application for a limited exemption from Puc 2100 or a part thereof, served on all entities on the
service list of this rulemaking docket as provided in (n) and (o) below.
(n) A multi-state utility may file for an exemption for transactions conducted between
the utility solely in its capacity serving its jurisdictional areas wholly outside of New Hampshire,
and its affiliates.
(o) The applicant has the burden of proof in an application for exemption pursuant to
(h) and (j) above.
(p) Puc 2100 shall be interpreted broadly, to effectuate our stated objectives of
fostering competition and protecting consumer interests.
(q) If any provision of Puc 2100, or the application thereof to any person, company,
or circumstance, is held invalid, the remainder of Puc 2100, or the application of such provision
to other persons, companies, or circumstances, shall not be affected thereby.
PART Puc 2103 NONDISCRIMINATION
Puc 2103.01 No Preferential Treatment.
(a) Unless otherwise authorized by the Commission or the FERC, or permitted by
Puc 2100, a utility shall not:
(1) Represent that, as a result of the affiliation with the utility, its affiliates or
customers of its affiliates shall receive any different treatment by the utility than
the treatment the utility provides to other, unaffiliated companies or their
customers; or
(2) Provide its affiliates, or customers of its affiliates, any preference,
including but not limited to preferences in terms, conditions, pricing, or timing,
over non-affiliated suppliers or their customers in the provision of services
provided by the utility.
Puc 2103.02 Affiliate Transactions.
(a) Transactions between a utility and its affiliates shall be limited to tariffed products
and services, the sale or purchase of goods, property, products or services made generally
available by the utility or an affiliate to all market participants through an open, competitive
bidding process, or as provided for in Puc 2105.02 and Puc 2105.03 regarding joint purchases
and corporate support, and Puc 2107 regarding new products and services provided the
transactions provided for in Puc 2103 comply with the provisions of Puc 2000, titled Supplier
Registration Rules, and Puc 2100.
(b) Except as provided for in Puc 2105, and Puc 2107, provided the transactions
provided for in Puc 2107 comply with Puc 2100, a utility shall provide access to utility
information or services, on the same terms for all similarly situated market participants.
(c) If a utility provides services or information to its affiliate(s), it shall
contemporaneously make the offering available to all similarly situated market participants,
which include all competitors serving the same market as the utility's affiliates.
(d) Except when made generally available by the utility through an open, competitive
bidding process, if a utility offers a discount or waives all or any part of any other charge or fee
to its affiliates, or offers a discount or waiver for a transaction in which its affiliates are involved,
the utility shall contemporaneously make such discount or waiver available to all similarly
situated market participants.
(e) The utilities should not use the "similarly situated" qualification, as used in (d)
above, to create such a unique discount arrangement with their affiliates such that no competitor
could be considered similarly situated.
(f) All competitors serving the same market as the utility's affiliates should be
offered the same discount as the discount received by the affiliates.
(g) A utility shall document the cost differential underlying the discount to its
affiliates in the affiliate discount report described in (n) and (o) below.
(h) If a tariff provision allows for discretion in its application, a utility shall apply that
tariff provision in the same manner to its affiliates and other market participants and their
respective customers.
(i) If a utility has no discretion in the application of a tariff provision, the utility shall
strictly enforce that tariff provision.
(j) A utility shall process requests for similar services provided by the utility in the
same manner and within the same time for its affiliates and for all other market participants and
their respective customers.
(k) A utility shall not condition or otherwise tie the provision of any services
provided by the utility, nor the availability of discounts of rates or other charges or fees, rebates,
or waivers of terms and conditions of any services provided by the utility, to the taking of any
goods or services from its affiliates.
(l) A utility shall not assign customers to which it currently provides services to any
of its affiliates, whether by default, direct assignment, option or by any other means, unless that
means is equally available to all competitors.
(m) Except as otherwise provided in Puc 2100, a utility shall not:
(1) Provide leads to its affiliates;
(2) Solicit business on behalf of its affiliates;
(3) Acquire information on behalf of or to provide to its affiliates;
(4) Share market analysis reports or any other types of proprietary or non-publicly available reports, including but not limited to market, forecast, planning
or strategic reports, with its affiliates;
(5) Request authorization from its customers to pass on customer information
exclusively to its affiliates;
(6) Give the appearance that the utility speaks on behalf of its affiliates or that
the customer will receive preferential treatment as a consequence of conducting
business with the affiliates; or
(7) Give any appearance that the affiliate speaks on behalf of the utility.
(n) If a utility provides its affiliates a discount, rebate, or other waiver of any charge
or fee associated with services provided by the utility, the utility shall, within 24 hours of the
time at which the service provided by the utility is so provided, post a notice on its electronic
bulletin board reporting this information.
(o) To provide notice of the discount offering as described in (n) above, the utility
shall post the following information on its electronic bulletin board:
(1) The name of the affiliate involved in the transaction;
(2) The rate charged;
(3) The maximum rate;
(4) The time period for which the discount or waiver applies;
(5) The quantities involved in the transaction;
(6) The delivery points involved in the transaction;
(7) Any conditions or requirements applicable to the discount or waiver;
(8) A documentation of the cost differential underlying the discount as
required in (d) above; and
(9) Procedures by which a nonaffiliated entity may request a comparable
offer.
(p) A utility that provides an affiliate a discounted rate, rebate, or other waiver of a
charge or fee associated with services provided by the utility shall maintain, for each billing
period, the following information:
(1) The name of the entity being provided services provided by the utility in
the transaction;
(2) The affiliate's role in the transaction, such as shipper, marketer, supplier,
or seller;
(3) The duration of the discount or waiver;
(4) The maximum rate;
(5) The rate or fee actually charged during the billing period; and
(6) The quantity of products or services scheduled at the discounted rate
during the billing period for each delivery point.
(q) All records maintained pursuant to Puc 2100 shall also conform to FERC rules
where applicable.
PART Puc 2104 DISCLOSURE AND INFORMATION
Puc 2104.01 Customer Information.
(a) A utility shall provide customer information to its affiliates and unaffiliated
entities on a strictly non-discriminatory basis, and only with prior affirmative customer consent.
(b) A utility shall make non-customer specific non-public information, including but
not limited to information about a utility's electricity purchases, sales, or operations or about the
utility's electricity-related goods or services, available to the utility's affiliates only if the utility
makes that information contemporaneously available to all other service providers on the same
terms and conditions, and keeps the information open to public inspection.
(c) Unless otherwise provided by Puc 2100, a utility continues to be bound by all
Commission-adopted pricing and reporting guidelines for such transactions.
Puc 2104.02 Service Provider Information.
(a) Except as otherwise authorized by the Commission and pursuant to a request by a
customer, a utility shall not provide its customers with any list of service providers, which
includes or identifies the utility's affiliates, regardless of whether such list also includes or
identifies the names of unaffiliated entities.
(b) If a customer requests information about any affiliated service provider, the utility
shall provide a list of all providers of electricity-related, or other utility-related goods and
services operating in its service territory, including its affiliates.
(c) Any service provider may request that it be included on such list, and, barring
Commission direction, the utility shall honor such request.
(d) Where maintenance of such list would be unduly burdensome due to the number
of service providers, subject to Commission approval, the utility shall:
(1) Direct the customer to a generally available listing of service providers,
such as, for example the Yellow Pages ; and
(2) Shall not be required to provide a list.
(e) The list of service providers provided shall make clear that the Commission does
not guarantee the financial stability or service quality of the service providers listed by the act of
approving this list.
Puc 2104.04 Supplier Information.
(a) A utility may provide non-public information and data which has been received
from unaffiliated suppliers to its affiliates or non-affiliated entities only if the utility first obtains
written affirmative authorization to do so from the supplier.
(b) A utility shall not actively solicit the release of such information exclusively to its
own affiliate in an effort to keep such information from other unaffiliated entities.
(c) Except as otherwise provided in Puc 2100, a utility shall not offer or provide
customers advice or assistance with regard to its affiliates or other service providers.
(d) A utility shall maintain contemporaneous records documenting all tariffed and
non-tariffed transactions with its affiliates, including but not limited to, all waivers of tariff or
contract provisions and all discounts.
(e) A utility shall maintain the records required by (d) above for a minimum of three
years and longer if this Commission in other rules or another government agency so requires.
(f) The utility shall make such records available for third party review upon 72 hours'
notice, or at a time mutually agreeable to the utility and third party.
(g) A utility shall maintain a record of all contracts and related bids for the provision
of work, products or services to and from the utility to its affiliates for no less than a period of
three years, and longer if this Commission or another government agency otherwise so requires.
(h) To the extent that reporting rules imposed by the FERC require more detailed
information or more expeditious reporting, nothing in these Rules shall be construed as
modifying the FERC rules.
PART Puc 2105 SEPARATION
Puc 2105.01 Corporate Entities.
(a) A utility and its affiliates shall be separate corporate entities.
(b) A utility and its affiliates shall keep separate books and records.
(c) Utility books and records shall be kept in accordance with applicable Uniform
System of Accounts (USOA) and Generally Accepted Accounting Procedures (GAAP).
(d) The books and records of affiliates shall be open for examination by the
Commission.
(e) A utility shall not share office space, office equipment, services, and systems with
its affiliates, nor shall a utility access the computer or information systems of its affiliates or
allow its affiliates to access its computer or information systems, except to the extent appropriate
to perform shared corporate support functions permitted under Puc 2105.
(f) Physical separation required by this section shall be accomplished preferably by
having office space in a separate building, or, in the alternative, through the use of separate
elevator banks and/or security-controlled access.
(g) This section does not preclude a utility from offering a joint service provided this
service is authorized by the Commission and is available to all non-affiliated service providers on
the same terms and conditions.
Puc 2105.02 Joint Purchases.
(a) To the extent not precluded by any other Commission rule, the utilities and their
affiliates may make joint purchases of goods and services, but not those associated with the
traditional utility merchant function.
(b) For purpose of this section, to the extent that a utility is engaged in the marketing
of the commodity of electricity to customers, as opposed to the marketing of transmission and
distribution services, it is engaging in merchant functions.
(c) Examples of permissible joint purchases include joint purchases of office supplies
and telephone services. Examples of joint purchases not permitted include electric power
purchases for resale, purchasing of electric transmission, systems operations, and marketing.
(d) The utility must insure that all joint purchases are priced, reported, and conducted
in a manner that permits clear identification of the utility and affiliate portions of such purchases,
and in accordance with applicable Commission allocation and reporting rules.
(e) As a general principle, a utility, its parent holding company, or a separate affiliate
created solely to perform corporate support services may share with its affiliates joint corporate
oversight, governance, support systems and personnel.
(f) Any shared support shall be priced, reported and conducted in accordance with the
Separation and Information Standards set forth herein, as well as other applicable Commission
pricing and reporting requirements.
(g) As a general principle, such joint utilization shall not allow or provide a means for
the transfer of confidential information from the utility to the affiliate, create the opportunity for
preferential treatment or unfair competitive advantage, lead to customer confusion, or create
significant opportunities for cross-subsidization of affiliates.
(h) In the compliance plan, a corporate officer from the utility and holding company
shall verify the adequacy of the specific mechanisms and procedures in place to ensure the utility
follows the mandates of this paragraph, and to ensure the utility is not utilizing joint corporate
support services as a conduit to circumvent Puc 2100.
(i) Examples of services that may be shared include: payroll, taxes, shareholder
services, insurance, financial reporting, financial planning and analysis, corporate accounting,
corporate security, human resources, including the compensation, benefits and employment
policies functions, employee records, regulatory affairs, lobbying, legal, and pension
management.
(j) Examples of services that may not be shared include: employee recruiting,
engineering, hedging and financial derivatives and arbitrage services, purchasing for resale,
purchasing of electric transmission, system operations, and marketing.
Puc 2105.03 Corporate Identification and Advertising.
(a) A utility shall not trade upon, promote, or advertise its affiliate's affiliation with
the utility, nor allow the utility name or logo to be used by the affiliate or in any material
circulated by the affiliate, unless it discloses in plain legible or audible language, on the first page
or at the first point where the utility name or logo appears that:
(1) The affiliate is not the same company as the utility;
(2) The affiliate is not regulated by the New Hampshire Public Utilities
Commission; and
(3) A statement that, "you do not have to buy [the affiliate's] products in order
to continue to receive quality regulated services from the utility."
(b) The application of the name/logo disclaimer is limited to the use of the name or
logo in New Hampshire.
(c) A utility, through action or words, shall not represent that, as a result of the
affiliate's affiliation with the utility, its affiliates will receive any different treatment than other
service providers.
(d) A utility shall not offer or provide to its affiliates advertising space in utility
billing envelopes or any other form of utility customer written communication unless it provides
access to all other unaffiliated service providers on the same terms and conditions.
(e) A utility shall not participate in joint advertising or joint marketing with its
affiliates.
(f) The prohibition on joint advertising and marketing means that utilities may
engage or shall not engage, as described below, in activities, including but not limited to the
following:
(1) A utility shall not participate with its affiliates in joint sales calls, through
joint call centers or otherwise, or joint proposals, including responses to requests
for proposals (RFPs), to existing or potential customers;
(2) At a customer's unsolicited request, a utility may participate, on a
nondiscriminatory basis, in non-sales meetings with its affiliates or any other
market participant to discuss technical or operational subjects regarding the
utility's provision of transportation service to the customer;
(3) Except as otherwise provided for by Puc 2100, a utility shall not
participate in any joint activities with its affiliates, including but not limited to,
not participating jointly with any affiliate in advertising, sales, marketing,
communications and correspondence with any existing or potential customer; or
(4) A utility shall not participate with its affiliates in trade shows,
conferences, or other information or marketing events held in New Hampshire.
(g) A utility shall not share or subsidize costs, fees, or payments with its affiliates
associated with research and development activities or investment in advanced technology
research.
Puc 2105.04 Employees.
(a) Except as otherwise permitted by these rules, a utility and its affiliates shall not
jointly employ the same employees including members of the boards of directors and corporate
officers, except as provided in below.
(b) The prohibition on a utility and its affiliate hiring joint employees shall not apply
in the following circumstances:
(c) In instances when this Rule is applicable to holding companies, any board
member or corporate officer may serve on the holding company and with either the utility or
affiliate (but not both).
(d) Where the utility is a multi-state utility, is not a member of a holding company
structure, and assumes the corporate governance functions for the affiliates, the prohibition
against any board member or corporate officer of the utility also serving as a board member or
corporate officer of an affiliate shall only apply to affiliates that operate within New Hampshire.
(e) In the case of shared directors and officers, a corporate officer from the utility and
holding company shall verify in the utility's compliance plan the adequacy of the specific
mechanisms and procedures in place to ensure that the utility is not utilizing shared officers and
directors as a conduit to circumvent any provision of Puc 2100.
(f) All employee movement between a utility and its affiliates shall comply with the
following provisions:
(1) A utility shall track and report to the Commission all employee movement
between the utility and affiliates;
(2) The utility shall file with the Commission annually its report on employee
movement between the utility and its affiliates;
(3) Once an employee of a utility becomes an employee of an affiliate, the
employee shall not return to the utility for a period of one year;
(4) The prohibition on returning to employment with the utility shall be
inapplicable if the affiliate to which the employee transfers goes out of business
during the one-year period;
(5) In the event that an employee returns to the utility after being employed by
a affiliate, after a one year period, or shorter if the affiliate went out of business
during the one year period, such employee cannot later be retransferred to,
reassigned to, or otherwise employed by the affiliate for a period of two years;
(6) Employees transferring from the utility to the affiliate are expressly
prohibited from using information gained from the utility in a discriminatory or
exclusive fashion, to the benefit of the affiliate or to the detriment of other
unaffiliated service providers;
(7) When an employee of a utility is transferred, assigned, or otherwise
employed by the affiliate, the affiliate shall make a one-time payment to the utility
in an amount equivalent to 25% of the employee's base annual compensation,
unless the utility can demonstrate that some lesser percentage, which shall be
equal to at least 15%, is appropriate for the class of employee included;
(8) All such fees as described in this paragraph paid to the utility shall be
accounted for by the utility in a separate memorandum account to track them for
future rate making treatment on an annual basis, or as otherwise necessary to
ensure that the utility's ratepayers receive the fees;
(9) The transfer payment provision shall not apply to clerical workers or to the
initial transfer of employees to the utility's holding company to perform corporate
support functions or to a separate affiliate performing corporate support functions,
provided that that transfer is made during the initial implementation period of Puc
2100;
(10) The transfer payment provision shall apply to any subsequent transfers or
assignments between a utility and its affiliates of all covered employees at a later
time;
(11) Any utility employee hired by an affiliate shall not remove or otherwise
provide information to the affiliate which the affiliate would otherwise be
precluded from having pursuant to Puc 2100; or
(12) A utility shall not make temporary or intermittent assignments, or
rotations to its affiliates.
Puc 2105.05 Transfer of Goods and Services.
(a) To the extent that these Rules do not prohibit transfers of goods and services
between a utility and its affiliates, all such transfers shall be subject to the following pricing
provisions:
(1) Transfers from the utility to its affiliates of goods and services produced,
purchased or developed for sale on the open market by the utility shall be priced
at fair market value;
(2) Transfers from an affiliate to the utility of goods and services produced,
purchased or developed for sale on the open market by the affiliate shall be priced
at no more than fair market value;
(3) For goods or services for which the price is regulated by a state or federal
agency, that price shall be deemed to be the fair market value, except that in cases
where more than one state commission regulates the price of goods or services,
this Commission's pricing provisions govern;
(4) Goods and services produced, purchased or developed for sale on the open
market by the utility shall be provided to its affiliates and unaffiliated companies
on a nondiscriminatory basis, except as otherwise required or permitted by Puc
2100 or applicable law;
(5) Transfers from the utility to its affiliates of goods and services not
produced, purchased or developed for sale by the utility will be priced at fully
loaded cost plus 5% of direct labor cost; AND
(6) Transfers from an affiliate to the utility of goods and services not
produced, purchased or developed for sale by the affiliate will be priced at the
lower of fully loaded cost or fair market value.
PART Puc 2106 REGULATORY OVERSIGHT
PART Puc 2106.01 Compliance Plans.
(a) Each utility shall include in its compliance filing a plan demonstrating to the
Commission that there are adequate procedures in place that will preclude the sharing of
information with its affiliates that is prohibited by Puc 2100.
(b) Upon the creation of a new affiliate which is regulated by Puc 2100, the utility
shall immediately notify the Commission of the creation of the new affiliate, as well as posting
notice on its electronic bulletin board.
(c) No later than 60 days after the creation of a new affiliate, the utility shall file an
amended compliance plan with the Commission, with a copy served on members of the service
lists to this rulemaking proceeding.
(d) The amended plan described in this part shall demonstrate how the utility will
implement and comply with the provisions of Puc 2100 with respect to the new affiliate.
Puc 2106.02 Affiliate Audit.
(a) No later than December 31 of each year, the utility shall have audits prepared by
independent auditors that verify that the utility is in compliance with Puc 2100.
(b) The utilities shall file this audit with the Commission no later than March 1 of the
following year, and serve a copy of this audit on all members of the service list of this
rulemaking proceeding.
(c) The audits described in this section shall be prepared at shareholder expense and
shall not be charged to ratepayers.
(d) Affiliate officers and employees shall be made available to testify before the
Commission as necessary or required on all maters relating to audits or compliance plans,
without subpoena.