U-1

                                                         FILE NO.



                 SECURITIES AND EXCHANGE COMMISSION
                      Washington, D.C. 20549
                              FORM U-1
                  APPLICATION/DECLARATION UNDER THE
              PUBLIC UTILITY HOLDING COMPANY ACT OF 1935

        WITH RESPECT TO THE ISSUANCE OF RATE REDUCTION BONDS
                      AND RELATED TRANSACTIONS

The Connecticut Light             Western Massachusetts Electric Company
  and Power Company               174 Brush Hill Avenue
107 Selden Street                 West Springfield, MA 01090
Berlin, CT 06037

               Public Service Company of New Hampshire
                           1000 Elm Street
                         Manchester, NH 03101
    (Names of companies filing this statement and addresses of principal
                             executive offices)

                         NORTHEAST UTILITIES
                (Name of top registered holding company)
                            Cheryl W. Grise
             Senior Vice President, Secretary and General Counsel
                   Northeast Utilities Service Company
                           107 Selden Street
                            Berlin, CT 06037
                  (Name and address of agent for service)
The Commission is requested to mail signed copies of all orders, notices
                        and communications to:

Jeffrey C. Miller, Esq.                 Randy A. Shoop
Assistant General Counsel               Assistant Treasurer - Finance
Northeast Utilities Service Company     Northeast Utilities Service Company
P.O. Box 270                            P.O. Box 270
Hartford, CT 06141-0270                 Hartford, CT 06141-0270




                      Richard J. Wasserman, Esq.
                      Day, Berry & Howard LLP
                            CityPlace I
                      Hartford, CT 06103-3499



                I.  DESCRIPTION OF PROPOSED TRANSACTIONS

                A.  Introduction

1.  The Connecticut Light and Power Company ("CL&P"), Western
Massachusetts Electric Company ("WMECO"), and Public Service Company of New
Hampshire ("PSNH" and, together with CL&P and WMECO, each a "Utility" and
collectively the "Utilities"), each an electric utility subsidiary of
Northeast Utilities ("NU"), a public holding company registered under the
Public Utility Holding Company Act of 1935, as amended (the "Act"), hereby
submit this application/declaration (the "Application") pursuant to Sections
6(a), 7, 9(a), 10, 12(b), (c), (f) and (g), and 13(b) of the Act and Rules
45(a), 45(b)(4), 46(a), 90 and 91 thereunder with respect to certain proposed
transactions.  Such proposed transactions involve (a) the formation of
several new subsidiaries, which are expected to be limited liability
companies (each a special purpose entity, or "SPE"); (b) the acquisition by
each Utility of the equity interests in one or more SPEs; (c) the making of
capital contributions by each of the Utilities to one or more SPEs; (d) the
periodic payment by each SPE to the applicable Utility of any pre-tax
investment income earned on such capital contributions; (e) the sale of RRB
Property (as discussed and defined below) by each Utility to one or more SPEs
in exchange for the net proceeds from the sale of RRBs (as discussed and
defined below); (f) the issuance by the SPEs of RRBs or other related debt
instruments either to the public or to a special purpose trust created by the
agencies of the relevant state; and (g) the entry by each of the Utilities
into servicing agreements and administration agreements with the SPEs.  The
Utilities further request that the Securities and Exchange Commission (the
"Commission") grant such other authorizations as may be necessary in
connection with the transactions described herein.  As described in greater
detail herein, the authorizations sought relate to the issuance of RRBs in
stranded cost securitization transactions in connection with electric utility
restructuring in Connecticut, Massachusetts, and New Hampshire.  The
Commission has recently authorized similar rate reduction bond transactions.
See West Penn Power Company, HCAR No. 27091 (October 19, 1999); Central and
South West Corporation, HCAR No. 27168 (April 20, 2000).

2.  In a previous proceeding under the Act - see Northeast Utilities,
et al., Application/Declaration on Form U-1, as amended, File No. 70-9541
(the "Use of Proceeds Filing"), granted and permitted to become effective in
HCAR No. 27147 (March 7, 2000) (the "Use of Proceeds Order") - the Utilities
sought and were granted authorization related to the use of proceeds from
various restructuring transactions, including the issuance of the RRBs
described herein. (FN 1)

                   B.  Background

3.  The states in which CL&P, WMECO, and PSNH operate - Connecticut,
Massachusetts, and New Hampshire, respectively - have enacted legislation
that restructures the electric industries in such states by introducing
retail competition in electricity generation.(FN 2)  The new laws allow
customers to choose their electric suppliers.  Accordingly, energy prices
will be based on competitive market forces rather than being set by the
appropriate regulatory commission.  The transmission and distribution of
electricity will continue to be provided by the local utilities at regulated
rates.  The restructuring statutes also require electric utilities to
institute rate reductions in amounts that vary from state to state.  More
detailed accounts of the restructuring of the electric industries in
Connecticut, Massachusetts, and New Hampshire are contained in the Use of
Proceeds Filing.

4.  Prior to restructuring, electric utilities had monopolies to
provide retail electric service within their service areas, with rates for
retail sales of electricity established through the regulatory process.  This
generally enabled electric utilities to recover energy costs, costs of
operations, depreciation attributable to capital costs, taxes, and a
reasonable return on capital investment through its rates.  Electric
utilities were often required by the states in which they operate to
construct generation facilities and enter into long-term contracts to buy
power from non-utility generators.  In a regulated market, electric utilities
could expect to recover these and other prudently incurred costs through rate
setting procedures.

5.  In light of the transition to the new competitive environment,
electric utilities will have certain "stranded costs" - i.e., costs that
would have been recoverable in a regulated environment but are not expected
to be recoverable as a result of the introduction of competition in the
generation market.  Such stranded costs may include previously incurred costs
associated with generation facilities that have market values below their
book value, costs associated with contracts to purchase electricity at above-
market prices, and other external costs.  To facilitate the transition, the
restructuring statutes contain provisions which permit electric utilities to
recover some or all of these costs through the collection from consumers of
electricity located within the service area of the electric utility of a non-
bypassable special charge (the "Transition Charge") (FN 3) that is based on
the amount of electricity purchased by consumers, regardless of whether such
consumer continues to purchase electricity from that electric utility.

6.  The restructuring statutes in Connecticut, Massachusetts, and New
Hampshire each provide for the use of securitization to facilitate utility
restructurings. (FN 4) Under these securitization provisions (with respect to
each state, the "Securitization Act" and, collectively, the "Securitization
Acts"), electric utilities may petition the state public utilities commission
for an order authorizing and setting forth the details of the securitization
transaction (such order, a "Financing Order").  Generally, the use of
securitization helps to reduce the carrying charge associated with electric
utilities' stranded costs and results in lower rates for customers, thereby
helping to achieve the overall rate reduction envisioned by electric industry
restructuring.  Thus, securitization is an important component of electric
industry restructuring which allows utilities and regulators to work
collaboratively to reduce customer rates and speed the introduction of
competition.

7.  The Securitization Acts each contain several important
characteristics that are necessary in order for any securities issued as part
of a securitization transaction to achieve investment grade ratings.  These
include the following:

    A portion of the Transition Charge may be securitized (such portion, the
"RRB Charge").  The right of the utility to collect the RRB Charge is
irrevocable, pursuant to a pledge by the relevant state (as discussed in more
detail below), and the charge itself is non-bypassable to customers of the
utility regardless of such customers' source of electric power.

    The right to collect the RRB Charge is established as a separate
property right (the "RRB Property") that includes all right, title, and
interest in and to all revenues, collections, claims, payments, money, or
proceeds of or arising from the RRB Charge.

    The RRB Property may be transferred by the electric utility to an SPE in
a transaction that is treated as a true sale for bankruptcy purposes.  As
such, if the electric utility were to become the subject of a bankruptcy
proceeding, the RRB Property would not be part of the electric utility's
bankruptcy estate and therefore would not be subject to the claims of the
electric utility's creditors.

    The electric utility is authorized to cause the issuance and sale of
"electric rate reduction bonds" or "rate reduction bonds" ("RRBs").  The RRB
Property is the principal asset underlying the RRBs.

    Any Financing Order issued must include a procedure for the periodic
adjustment of RRB Charges.  This true-up mechanism serves to reconcile the
actual RRB Charges collected against the RRB Charges expected to have been
collected.  This true-up mechanism, however, does not involve any recourse to
the electric utility.

    The state pledges and agrees that neither it nor any agency thereof will
alter, amend, reduce or impair the Transition Charge, the RRB Charge, the RRB
Property or the Financing Order and all rights thereunder, until RRBs and any
interest, fees and expenses associated therewith are fully discharged, unless
adequate provision is made for the protection of the owners of the RRB
Property and holders of RRBs.

               C.  The Structure of the Proposed Transactions

8.  In accordance with the legislative requirements described above,
the Utilities each intend to use securitization as a means of recovering a
portion of the stranded costs incurred as a result of electric industry
restructuring in Connecticut, Massachusetts, and New Hampshire.  In
connection therewith, the Utilities have each applied for a Financing Order
from the appropriate state public utilities commission.  The structure of the
transactions for each Utility will be substantially similar and will
generally follow one of two formats.  The first format (the "One Security
Format") is set forth below.  Because of the similarities to the One Security
Format, the alternative format (the "Two Securities Format") will be
described below, but only to the extent that it differs from the One Security
Format.

             (i)  The One Security Format

           (a)  Formation and Capitalization of the SPE

9.  The Utility will cause the organization of one or more bankruptcy
remote, wholly-owned SPEs, each of which is expected to be a Delaware limited
liability company authorized to acquire RRB Property and to issue RRBs.  The
utility will contribute as equity to the SPE cash equal to at least 0.50% of
the initial principal balance of RRBs issued with respect to such SPE (the
"Capital Amount").  This capitalization is required in order that the Utility
may treat the RRB issuance by the SPE as debt for tax purposes.  The SPE will
invest the equity in financial instruments that are issued by parties
unaffiliated with the Utility and that can be readily converted to cash.
Investment earnings on the Capital Amount, to the extent not used to satisfy
the RRBs, will be paid to the Utility periodically.  The Capital Amount and
any investment earnings thereon, to the extent not used to satisfy the RRBs,
will be returned to the Utility after the RRBs are paid in full.

10.  It is anticipated that the SPE will enter into an administration
agreement (the "Administration Agreement") with the Utility, pursuant to
which the Utility shall perform administrative services and provide
facilities for the SPE to ensure that it is able to perform such day-to-day
operations as are necessary to maintain its existence and perform its
obligations under the securitization transaction documents.  Under the
Administration Agreement, the Utility will be entitled to receive an
administration fee for its provision of such services and facilities.  In
order to support the SPE's status as a bankruptcy remote entity, separate and
apart from the Utility, and to satisfy related rating agency and legal
opinion requirements, the administration fee must be comparable to one
negotiated in a market-based, arm's-length transaction - i.e., reasonable and
sufficient for a similar, unaffiliated entity providing such services and
facilities.  Although this fee is expected to approximate each Utility's
estimate of the actual cost of providing these services and facilities, (FN
5) the Utilities cannot be certain that this fee will meet the "at cost"
requirements of Section 13(b) of the Act and Rules 90 and 91 thereunder. (FN
6) Accordingly, the Utilities request an exemption from these requirements.

              (b)  Sale of RRB Property

11.  The Utility will sell the RRB Property to an SPE for an amount
equal to the issue price of the RRBs less any transaction costs paid by the
SPE from the proceeds of the RRBs.  As provided for in the Securitization
Acts, it is expected that the transfer will constitute a true sale for
bankruptcy and commercial law purposes.  Although the Utility will collect
the billed RRB Charge as servicer for the RRBs (see paragraph 17 below), for
legal purposes, the RRB Property will remain isolated from the Utility's
revenues and assets.  Isolating the RRB Property in this manner is intended
to improve the likelihood that the RRBs will receive the highest possible
credit rating.

                (c)  Issuance of RRBs

12.  Pursuant to the Securitization Acts, the SPE will issue RRBs to
underwriters.  Such underwriters in turn will sell the RRBs to public
investors.  Each Utility presently expects that the following principal
amount of RRBs will be issued on its behalf on or before August 31, 2005(FN
7)

                      CL&P   not to exceed $1.489 billion

                      WMECO    not to exceed $303 million

                      PSNH     not to exceed $725 million

13.  The RRBs will be in the form of promissory notes of the SPE.  The
RRBs will be nonrecourse to the Utility but will be secured by the assets of
the SPE, including (i) the RRB Property (including by a statutory lien on the
RRB Property as provided by the Securitization Acts), (ii) the accounts
maintained by the SPE for payments on the RRBs (together the "Collection
Account"), (iii) all amounts or investment property on deposit in or credited
to the Collection Account from time to time, (iv) all other property of
whatever kind (other than certain amounts owing to certain service providers)
owned from time to time by the SPE, and (v) all rights of the SPE in and to
the transaction documents, such as (a) the purchase agreement by which the
SPE acquires the RRB Property and (b) the servicing agreement (the "Servicing
Agreement") by which the Utility or any successor thereto acts as servicer
(the "Servicer") for the RRB Property (as discussed in more detail in
paragraph 17 below).  The RRBs will not be subordinated to the claims of any
creditors or the equity owner of the SPE, other than for payments of trustee,
servicing, and administrative fees.

14.  The RRBs will be issued in one or more series.  Each series of RRBs
may be offered in one or more classes, each expected to have a different
principal amount, term, interest rate, and amortization schedule.  Each
Utility expects that the weighted average all-in cost of the RRBs issued on
its behalf will not exceed the applicable U.S. Treasury bond benchmark
security plus 300 basis points.  The Utilities also expect that the RRBs will
have legal maturities not longer than 15 years and that the longest-term RRBs
will have scheduled maturities that are at least 6 months earlier, as
necessary to meet the rating agencies' triple-A rating standards. (FN 8)
Other terms and characteristics of the RRBs will be determined at the time of
issuance based on then-current market conditions.  The SPE may enter into
swap agreements or other hedging arrangements solely to permit the issuance
of variable rate RRBs.  The cost of any such agreements or arrangements will
be included in the weighted average all-in cost calculation referred to
above.

15.  The SPE and the holders of the RRBs will expressly agree under the
terms of the applicable transaction documents to treat the RRBs as debt of
the SPE for all purposes.  For the Utility's financial reporting purposes,
the RRBs will be treated as debt of the Utility, but the RRBs will not be
recourse obligations of the Utility and will not be treated as debt of the
utility for rating agency purposes. (FN 9)

16.  The SPE will transfer to the Utility, as consideration for the
transfer of the RRB Property to the SPE, the proceeds from the issuance of
the RRBs, net of its transaction expenses.  The Utilities plan to apply the
proceeds of securitization, among other things, to pay for transaction costs,
to buy out or renegotiate existing purchased power agreements with
independent power producers, and to reduce their capitalization.  The
proposed use of the proceeds from all of the restructuring transactions is
the subject of the Use of Proceeds Filing and the Use of Proceeds Order and
is set forth in greater detail therein.  The Utilities hereby incorporate by
reference and in its entirety the Use of Proceeds Filing.

                 (d)  Servicing the RRBs

17.  Through the transfer of the RRB Property to the SPE, the SPE will
obtain the right and the obligation to assess and collect the RRB Charge.  On
behalf of the SPE, the Utility will act initially as the Servicer for the RRB
Property and will be responsible for calculating, billing, collecting, and
remitting the RRB Charge from all present and future customers that are
obligated to pay such charge.  Therefore, the Utility will carry out billing
and collection activities both as Servicer with respect to the RRB Charge and
as principal with respect to its own charges to be paid by such customers.
The Utility can be replaced as Servicer only if it fails to perform its
obligation under the Servicing Agreement satisfactorily, and it can resign
only in limited circumstances.

18.  As Servicer, the Utility will bill and collect the RRB Charge and
retain all books and records regarding the RRB Charge, subject to the right
of the SPE to inspect those records.  The Utility, or any successor Servicer,
will periodically remit (as frequently as required by the rating agencies and
in all events within one calendar month of collection) the billed and
collected RRB Charge to the trustee appointed under an indenture in
connection with the issuance of the RRBs (the "RRB Trustee").  To the extent
that estimation of such collections is required, the Utility will design a
methodology that will be satisfactory to the rating agencies, and that will
approximate most closely actual collections.  The monies deposited with the
RRB Trustee will be held in the Collection Account.

19.  As initial Servicer, the Utility will be entitled to receive a
servicing fee for its servicing activities and reimbursement for certain of
its expenses in the manner set forth in the Servicing Agreement.  In order to
support the SPE's status as a bankruptcy remote entity, separate and apart
from the Utility, and to satisfy related rating agency and legal opinion
requirements, the servicing fee must be comparable to one negotiated in a
market-based, arm's-length transaction - i.e., reasonable and sufficient for
a similar, unaffiliated entity providing similar services.  Although this fee
is expected to approximate each Utility's estimate of the actual cost of
providing these services, (FN 10) the Utilities cannot be certain that this
fee will meet the "at cost" requirements of Section 13(b) of the Act and
Rules 90 and 91 thereunder. (FN 11) Accordingly, the Utilities request an
exemption from these requirements.  See Central and South West Corporation,
HCAR No. 27168 (April 20, 2000).

20.  The RRB Charge will be established at a level (or at different
levels during specified periods over the life of RRBs) intended to (i)
provide for the full recovery of payments of interest and principal on RRBs,
in accordance with the expected amortization schedule determined at the time
of offering, (ii) provide credit enhancement, including any liquidity
reserves and an amount for overcollateralization (the "Overcollateralization
Amount"), and (iii) provide for any related fees, costs and expenses - based
upon assumptions including sales forecasts, charge-offs, and lags between RRB
Charge billing and collection by the Servicer.

21.  The Overcollateralization Amount will eventually reach at least
0.50% of the initial principal amount of the RRBs, and will be collected
ratably over the expected term of the RRBs.  The Utility has been advised
that the Overcollateralization Amount is necessary for the RRBs to receive
the highest possible credit rating.

22.  As a result of the Overcollateralization Amount, the Utility
expects to receive RRB Charge collections in excess of the total amount that
will be paid on the RRBs plus the fees and expenses that will be paid by the
SPE.  After the date of the final payment of principal and interest on the
RRBs, this excess will be applied as a credit to the Transition Charge or the
Utility's other rates and charges that would otherwise be charged to the
Utility's customers.

23.  The level of the RRB Charge may differ during the term of the RRBs
due to several factors, including changes in the principal balance of the
RRBs, changes in the weighted average interest rate of RRBs as the relative
principal balance outstanding changes, the impact of the variability of
energy sales and customer movements in and out of the service territory, and
changes in ongoing fees, costs, and expenses of the RRBs.  In addition, the
amount of the RRB Charge remitted relative to the amount billed will likely
vary due to several factors, including changes in customer payment and
charge-off patterns.

                   (e)  Credit Enhancement

24.  In order to minimize the impact of variability in the remittance of
the RRB Charge on the payment of principal, interest, fees, costs and
expenses on RRBs, the Financing Order is expected to provide for the RRB
Charge to be adjusted by a true-up mechanism at least annually to keep actual
principal amortization in line with the expected amortization schedule.  By
means of this true-up mechanism, on at least an annual basis, the Utility, as
Servicer (or any successor Servicer) on behalf of the SPE, will file the
revised RRB Charge with the public utilities commission, which will become
effective shortly thereafter.

25.  Upon issuance of the initial series of RRBs, the SPE will establish
the Collection Account, which will consist of at least four subaccounts:  a
general subaccount (the "General Subaccount"), a reserve subaccount (the
"Reserve Subaccount"), a subaccount for the Overcollateralization Amount (the
"Overcollateralization Subaccount"), and a subaccount for the Capital Amount
(the "Capital Subaccount").  Additional subaccounts may be established in
respect of additional credit enhancements or as necessitated for convenience
by the transaction documents.  These accounts will be maintained and
administered in trust by the RRB Trustee.

26.  The billed and collected RRB Charge will be remitted to the
Collection Account.  Amounts in the Collection Account will be used to pay
the fees of the RRB Trustee, fees to the Servicer, administrative costs,
operating expenses of the SPE, accrued but unpaid interest on all classes of
the RRBs, and principal (to the extent scheduled) on the outstanding RRBs.
Any remaining billed and collected RRB Charge will be allocated to the
Capital Subaccount (to the extent that the Capital Subaccount is below the
required capital level), the Overcollateralization Subaccount (to the extent
scheduled), and then to the Reserve Subaccount.

27.  If the billed and collected RRB Charge in any period is
insufficient to satisfy the SPE's payment obligations on the RRBs, then
amounts in the Reserve Subaccount, the accumulated Overcollateralization
Amount, and Capital Amount will be used (in that order) to satisfy scheduled
principal and interest payments.  To the extent that the
Overcollateralization Amount or the Capital Amount is used to satisfy
principal and interest payments on the RRBs, the RRB Charge will be adjusted
in the future to restore those amounts.

28.  Investment earnings on amounts in the Collection Account also may
be used to satisfy scheduled interest and principal payments on RRBs and to
restore the Capital Amount and the scheduled Overcollateralization Amount.
Except for earnings on the Capital Subaccount, any excess earnings will be
remitted to the SPE and, after the last scheduled date for the payment of
accrued interest and principal on the bonds, will be distributed to the
Utility for the benefit of its customers.  As indicated above, investment
earnings on amounts in the Capital Subaccount, to the extent not used to
satisfy the RRBs, will be paid to the Utility periodically.  As also
indicated above, amounts in the Capital Subaccount and any investment
earnings thereon, to the extent not used to satisfy the RRBs, will be
returned to the Utility after the RRBs are paid in full.

29.  Other forms of credit enhancement customary for securitization
transactions also might be used, such as a liquidity reserve, debt service
reserve fund, bank letter of credit, or surety bond or similar insurance
policy.  If determined to be cost-effective, these forms of credit
enhancement will be implemented at the time of bond pricing and the related
cost will be recovered through the RRB Charge.  The cost of any such credit
enhancement will be included in the weighted average all-in cost calculation
referred to in paragraph 14 above.

                  (f)  Defaults

30.  The RRBs will provide for the following events of default:  (i) a
default in the payment of accrued interest on any class of RRBs (after a
specified grace period); (ii) a default in the payment of outstanding
principal as of the legal maturity date; (iii) a default in payment of the
redemption price following a call as of the redemption date; (iv) certain
breaches of covenants, representations or warranties by the SPE in the
indenture under which the RRBs are issued; and (v) certain events of
bankruptcy, insolvency, receivership or liquidation of the SPE.

31.  In the event of a payment default on the RRBs, the RRB Trustee or
holders of a majority in principal amount of all series then outstanding may
declare the principal of all classes of the RRBs to be immediately due and
payable.  If all classes of the RRBs have been declared to be due and payable
following an event of default, the RRB Trustee may, in its discretion, either
sell the RRB Property or allow the SPE to maintain possession of the RRB
Property and continue to apply receipts of the RRB Charge as if there had
been no declaration of acceleration.

              (ii)  Two Securities Format

32.  The alternative format that one or more of the Utilities might
follow with respect to the proposed transactions is the same as the One
Security Format in most respects.  However, under the Two Securities Format,
instead of issuing RRBs to capital market investors, the SPE will issue
promissory notes (the "SPE Debt Securities") to a governmentally-sponsored
trust established by one or more agencies of the state in which the Utility
operates (the "Trust").  The SPE Debt Securities will be secured by the same
assets of the SPE that the RRBs would be secured by under the One Security
Format - i.e., the RRB Property and all of the other assets of the SPE.
Overall, the characteristics of the SPE Debt Securities will be the same as
those described for the RRBs under the One Security Format.

33.  Under the Two Securities Format, the Trust will issue to
underwriters RRBs in aggregate principal amount equal to the aggregate
principal amount of the SPE Debt Securities.  Such underwriters in turn will
sell the RRBs to public investors.

34.  The RRBs will be in the form of pass-through certificates
representing beneficial ownership interests in the SPE Debt Securities held
by the Trust.  Each class of each series of RRBs will represent fractional
undivided beneficial interests in a class of a series of SPE Debt Securities
held by the Trust and the proceeds thereof.  Therefore, each class of RRBs
will have terms and characteristics that are substantially identical to the
corresponding class of SPE Debt Securities.  The RRBs will be secured by a
statutory lien on the RRB Property as provided by the Securitization Acts.
Under the Two Securities Format, the SPE or the Trust may enter into swap
agreements or other hedging arrangements solely to permit the issuance of
variable rate RRBs.  In such case, the RRBs would also represent beneficial
ownership interests in those agreements or arrangements. The cost of any such
agreements or arrangements will be included in the weighted average all-in
cost calculation referred to in paragraph 14 above.

35.  Under the Two Securities format, the Trust will transfer the
proceeds from the issuance of the RRBs, net of its transaction expenses, if
any, to the SPE, as consideration for the SPE Debt Securities.  The SPE will
then transfer to the Utility, as consideration for the transfer of the RRB
Property to the SPE, the balance of such RRB proceeds, net of any remaining
transaction expenses.

            D.  Statement Pursuant to Rule 54

36.  Except in accordance with the Act, neither NU nor any subsidiary
thereof (a) has acquired an ownership interest in an exempt wholesale
generator ("EWG") or a foreign utility company ("FUCO") as defined in
Sections 32 and 33 of the Act, or (b) now is or as a consequence of the
transactions proposed herein will become a party to, or has or will as a
consequence of the transactions proposed herein have a right under, a
service, sales, or construction contract with an EWG or a FUCO.  None of the
proceeds from the transactions proposed herein will be used by NU and its
subsidiaries to acquire any securities of, or any interest in, an EWG or a
FUCO.

37.  NU currently meets all of the conditions of Rule 53(a), except for
clause (1).  At March 31, 2000, NU's "aggregate investment," as defined in
Rule 53(a)(1), in EWGs and FUCOs was approximately $468.7 million, or
approximately 78.7% of NU's average "consolidated retained earnings," also as
defined in Rule 53(a)(1), for the four quarters ended March 31, 2000 ($595.6
million).  With respect to Rule 53(a)(1), however, the Commission has
determined that NU's financing of its investment in Northeast Generation
Company ("NGC"), NU's only current EWG or FUCO, in an amount greater than the
amount that would otherwise be allowed by Rule 53(a)(1) would not have either
of the adverse effects set forth in Rule 53(c).  See Northeast Utilities,
HCAR No. 27148 (March 7, 2000).

38.  In addition, NU and its subsidiaries are in compliance with the
other provisions of Rule 53(a) and (b), as demonstrated by the following
determinations:

          (i)   NGC maintains books and records, and prepares financial
          statements in accordance with Rule 53(a)(2).  Furthermore, NU
          has undertaken to provide the Commission access to such books
          and records and financial statements, as it may request.

(ii)  No employees of NU's public utility subsidiaries have rendered
services to NGC.

          (iii)NU has submitted (a) a copy of each Form U-1 and Rule 24
          certificate that has been filed with the Commission under Rule
          53 and (b) a copy of Item 9 of the Form U5S and Exhibits G and
          H thereof to each state regulator having jurisdiction over the
         retail rates of NU's public utility subsidiaries.

          (iv) Neither NU nor any subsidiary has been the subject of a
           bankruptcy or similar proceeding unless a plan of
           reorganization has been confirmed in such proceeding.

           (v) NU's average consolidated retained earnings for the four most
           recent quarterly periods have not decreased by 10% or more
           from the average for the previous four quarterly periods.

           (vi) In the previous fiscal year, NU did not report operating
           losses attributable to its investment in EWGs/FUCOs exceeding
           3 percent of NU's consolidated retained earnings.

              II.  FEES, COMMISSIONS AND EXPENSES

39.   The fees, commissions and expenses paid or incurred, or to be paid
or incurred, directly or indirectly, in connection with the proposed
transactions by the Utilities are expected to be comprised primarily of fees
for ordinary legal, accounting and investment banking services and are not
expected to exceed the following amounts, assuming the RRBs are fully issued:

                   CL&P   not to exceed $12 million

                   PSNH   not to exceed $8 million

                   WMECO  not to exceed $6 million


               III.  APPLICABLE STATUTORY PROVISIONS

40.  Sections 6(a), 7, 9(a), 10, 12(b), (c), (f) and (g), and 13(b) of
the Act and Rules 45(a), 45(b)(4), 46(a), 90 and 91 thereunder are or may be
applicable to the proposed transactions.  To the extent any other sections of
the Act or Rules thereunder may be applicable to the proposed transactions,
the Utilities request appropriate orders thereunder.  As noted above, the use
of proceeds from various restructuring transactions, including the issuance
of the RRBs, was the subject of the Use of Proceeds Filing and the Use of
Proceeds Order.

                        IV.  REGULATORY APPROVALS

41. CL&P, WMECO, and PSNH are seeking approval for the proposed
transactions from the Connecticut, Massachusetts, and New Hampshire public
utilities commissions respectively.  PSNH and WMECO will also request that
the Connecticut public utilities commission waive the requirement that it
approve their proposed RRB transactions.

                           V.  PROCEDURE

42.  The Utilities hereby request that the Commission publish a notice
under Rule 23 with respect to the filing of this Application as soon as
practicable and that the Commission's order be issued as soon as possible.  A
form of notice suitable for publication in the Federal Register is attached
hereto as Exhibit H.  The Utilities respectfully request the Commission's
approval, pursuant to this Application, of the consummation by the Utilities
on or prior to August 31, 2005 of all transactions described herein, whether
under the sections of the Act and Rules thereunder enumerated in Part III
above or otherwise.  It is further requested that the Commission issue a
single order authorizing the transactions proposed herein at the earliest
practicable date but in any event not later than August 15, 2000.
Additionally, the Utilities (i) request that there not be any recommended
decision by a hearing officer or by any responsible officer of the
Commission, (ii) consent to the Office of Public Utility Regulation within
the Division of Investment Management assisting in the preparation of the
Commission's decision, and (iii) waive the 30-day waiting period between the
issuance of the Commission's order and the date on which it is to become
effective, since it is desired that the Commission's order, when issued,
become effective immediately.

              VI.  EXHIBITS AND FINANCIAL STATEMENTS

43.  Exhibits.  Each Utility undertakes to file all material financing
documents relating to its RRB transaction with the certificate filed pursuant
to Rule 24 under the Act after the consummation of such transaction.  The
following exhibits are filed with this Application (or, if asterisked (*),
will be filed by amendment to this Application).

         *C 1  Registration Statement on Form S-3 for the CL&P RRBs

         *C 2  Registration Statement on Form S-3 for the WMECO RRBs

         *C 3   Registration Statement on Form S-3 for the PSNH RRBs

         D 1.1   Application of CL&P to the Connecticut Department of Public
Utility Control for Approval of the Issuance of Rate Reduction Bonds
and Related Transactions

         *D 1.2   Financing Order of the Connecticut Department of Public
Utility Control

          D 2.1   Petition of WMECO to the Massachusetts Department of
Telecommunications and Energy for Approval of the Issuance of Electric
Rate Reduction Bonds

          *D 2.2   Financing Order of the Massachusetts Department of
Telecommunications and Energy

          *D 2.3   Application of WMECO to the Connecticut Department of
Public Utility Control for Waiver of Approval for the Issuance of Electric
Rate Reduction Bonds

          *D 2.4   Connecticut Department of Public Utility Control Waiver of
Approval for the Issuance of Electric Rate Reduction Bonds by WMECO

          D 3.1    PSNH's Settlement Agreement (Exhibit 10.2, NU Form 10-Q
for Quarter ended June 30, 1999, File No. 1-5324)

          D 3.2.1 PSNH's Settlement Order

         *D 3.2.2 Finance Order of the New Hampshire Public Utilities
Commission

         *D 3.3  Application of PSNH to the Connecticut Department of Public
Utility Control for Waiver of Approval for the Issuance of Electric
Rate Reduction Bonds

         *D 3.4  Connecticut Department of Public Utility Control Waiver of
Approval for the Issuance of Electric Rate Reduction Bonds by PSNH

         *F  Opinion of Counsel

         *G 1  CL&P Financial Data Schedule

          *G 2  WMECO Financial Data Schedule

          *G 3  PSNH Financial Data Schedule

           H  Proposed Form of Notice

44.  Financial Statements.  The following financial statements will be filed
by amendment to this Application.

1.   Northeast Utilities (consolidated)

         1.1  Balance Sheet, per books and pro forma, as of March 31, 2000.

         1.2  Statement of Income, per books and pro forma, for 12 months
ended March 31, 2000 and capital structure, per books and pro forma, as
of March 31, 2000.

2.  Northeast Utilities (parent company only)

        2.1  Balance Sheet, per books and pro forma, as of March 31, 2000.

        2.2  Statement of Income, per books and pro forma, for 12 months
ended March 31, 2000 and capital structure, per books and pro forma, as
of March 31, 2000.

3.  The Connecticut Light and Power Company

          3.1  Balance Sheet, per books and pro forma, as of March 31, 2000.

          3.2  Statement of Income, per books and pro forma, for 12 months
ended March 31, 2000 and capital structure, per books and pro forma, as of
March 31, 2000.

4.  Western Massachusetts Electric Company

         4.1  Balance Sheet, per books and pro forma, as of March 31, 2000.

         4.2  Statement of Income, per books and pro forma, for 12 months
ended March 31, 2000 and capital structure, per books and pro forma, as
of March 31, 2000.

5.  Public Service Company of New Hampshire

         5.1  Balance Sheet, per books and pro forma, as of March 31, 2000.

         5.2  Statement of Income, per books and pro forma, for 12 months
ended March 31, 2000 and capital structure, per books and pro forma, as
of March 31, 2000.

           VII.  INFORMATION AS TO ENVIRONMENTAL EFFECTS

45.  (a)  The financial transactions described herein do not involve a
major Federal action significantly affecting the quality of the environment.

 (b)  No other federal agency has prepared or is preparing an
environmental impact statement with regard to the proposed transaction.

                            SIGNATURES

Pursuant to the requirements of the Public Utility Holding Company Act
of 1935, as amended, the undersigned companies have duly caused this
statement to be signed on their behalf by the undersigned thereunto duly
authorized.

THE CONNECTICUT LIGHT AND POWER COMPANY

By: /s/Randy A. Shoop
Randy A. Shoop
Treasurer

WESTERN MASSACHUSETTS ELECTRIC COMPANY
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE

By:  /s/Randy A. Shoop
Randy A. Shoop
Assistant Treasurer - Finance
Date: June 15, 2000


Footnotes:

1.  The authorizations sought in the Use of Proceeds Filing - and
granted by the Commission in the Use of Proceeds Order - related to the
capital restructuring of the NU system in connection with electric utility
restructuring in Connecticut, Massachusetts, and New Hampshire and the
related required asset divestitures and the issuance of rate reduction bonds
in such states. The Commission's authorization will permit NU and its
subsidiaries to use the proceeds of such divestitures and rate reduction bond
issuances, among other things, to reduce and adjust their capital structures
by retiring outstanding debt, preferred stock and common equity, and to buy
down existing power purchase agreements with independent power producers.

2.  An Act Concerning Electric Restructuring, 1998 Conn. Acts. 98-28
(Reg. Sess.); The Massachusetts Electric Industry Restructuring Act, 1997
Mass. Acts 164; N.H. Rev. Stat. Ann. ("RSA") 374-F.
In New Hampshire, the enactment of RSA 374-F was followed by several
governmental actions relating to electric industry restructuring, including:
(1) the initiation by the New Hampshire Public Utilities Commission (the
"NHPUC") of Docket No. DR 96-150, an administrative proceeding to consider
restructuring; (2) the issuance by the NHPUC on February 28, 1997 of a
restructuring order in Docket No. DR 96-150; (3) the enactment in 1999 of
1999 N.H. Laws 289, including RSA 369-A, which made certain changes to the
law regarding implementation of restructuring and authorized the NHPUC to
consider whether implementation of securitization will result in benefits to
customers and to issue an order approving securitization, subject to the
enactment of future enabling legislation; (4) the execution and delivery by
the Governor of New Hampshire, the Staff of the NHPUC, the Company, and
certain other parties of an Agreement to Settle PSNH Restructuring dated
August 2, 1999 (the "Settlement Agreement"), which is designed to, among
other things, to provide resolution to all major issues pertaining to PSNH in
Docket No. DR 96-150 and to result in the restructuring of PSNH in compliance
with the objectives of the legislature and the NHPUC; (5) following the
execution and delivery of the Settlement Agreement, the initiation by the
NHPUC of Docket No. DE 99-099, an administrative proceeding to consider the
Settlement Agreement, including the securitization proposal contained
therein; (6) the issuance by the NHPUC on April 19, 2000 of an order in
Docket No. DE 99-099 (Order No. 23,443) approving, with modifications and
conditions, the Settlement Agreement (the "Settlement Order"); and (7) the
enactment in 2000 of 2000 N.H. Laws 249, which, among other things, includes
securitization enabling legislation, RSA 369-B.

3.  Connecticut, Massachusetts, and New Hampshire use different terms to
refer to analogous securitization-related concepts.  Generic, non-state-
specific defined terms are used throughout this application to refer to such
concepts.

4.  See 1998 Conn. Acts. 98-28 (Reg. Sess.), Sections 8-14, codified at
Conn. Gen. Stat. Sections 16-245e to 16-245k; 1997 Mass. Acts 164, Section
193, codified at M.G.L. c. 164, Sections 1G-1H; RSA 369-B.
Securitization is the financing of a specific asset or pool of assets,
through the issuance of securities, frequently referred to as "asset-backed
securities" ("ABS").  For debt service and repayment of principal, these
securities rely solely on the revenue stream underlying the asset or pool of
assets, and as a result, their ratings are dependent upon the predictability
or volatility of that associated cash flow.  The structure of a typical ABS
transaction is based on the underlying assets and the expected cash flows to
be generated by those assets.  In general, the original owner of the
underlying asset sells the asset to a special-purpose financing entity.  That
entity then issues securities (directly or indirectly), for which the primary
source of payment of principal and interest is the cash flow generated by the
underlying asset that was sold.

5.  The annual administration fee applicable to each Utility's proposed
RRB transaction shall not exceed $75,000.

6.  Generally, Rule 91 requires "a fair and equitable allocation of
expenses" and allows "reasonable compensation for necessary capital
procured."

7.  The "not to exceed" principal amounts set forth below are consistent
with the authorizations sought by the Utilities in the Use of Proceeds Filing
and granted by the Commission in the Use of Proceeds Order.

8.  Legal maturity is the date on which nonpayment constitutes a
default.  Scheduled maturity is the date on which the final principal payment
is expected to be made.

The Utilities expect the Financing Orders to include guidance with
respect to RRB maturities.  The Securitization Acts also include such
guidance.  See Conn. Gen. Stat. Section 16-245j(c)(6); M.G.L. c. 164, Section
1H(b)(4)(vi); RSA 369-B:5, VIII.

9.  The Utilities note that, as a result of increased debt from the
issuance of the RRBs, NU and the Utilities will fall below the Commission's
benchmark 30% common equity-to-total capitalization ratio.  See Use of
Proceeds Order.

10.  The annual servicing fee applicable to CL&P's and WMECO's proposed
RRB transactions shall equal approximately 0.05% of the initial principal
balance of RRBs.  The annual servicing fee applicable to PSNH's proposed RRB
transaction shall equal approximately 0.25% of the outstanding principal
balance of RRBs.

The servicing fee paid to the Utility will be lower than the servicing
fee paid to a successor Servicer that does not concurrently bill the RRB
Charge with charges for other services due to the fact that the successor
Servicer would not otherwise be sending bills to and making collections from
customers, and therefore the cost to that successor Servicer associated with
servicing the RRB Charge and the RRBs is higher.

EX-99.1

                                                        EXHIBIT D 1.1

May 31, 2000

Ms. Louise Rickard
Acting Executive Secretary
Department of Public Utility Control
10 Franklin Square
New Britain, CT 06051


Re:	Docket No. 00-05-01

     Application of The Connecticut Light and Power Company for
Approval of the Issuance of Rate Reduction Bonds and Related
Transactions

Dear Ms. Rickard:

     The Connecticut Light and Power Company ("CL&P"), an electric utility
subsidiary of Northeast Utilities and a public service company as defined in
Connecticut General Statutes ("Conn. Gen. Stat.") Section 16-1, hereby
applies to the Department of Public Utility Control (the "Department") for
the issuance of a financing order (the "Financing Order") approving the
issuance of rate reduction bonds ("RRBs") for the recovery of certain
stranded costs and related transactions pursuant to Conn. Gen. Stat. Sections
16-245e to 16-245k (the "Securitization Statute").

     More specifically, CL&P requests that the Department issue a Financing
Order that includes a transaction description, findings, and orders and
approvals substantially similar to those contained in the Proposed
Transaction Description, Findings, and Orders and Approvals To Be Included in
Financing Order attached as Exhibit 4 to this Application, and in which,
among other things, the Department would:

          (i)  establish the transition property (referred to herein and in
the Securitization Statute as the "Transition Property"), including the non-
bypassable, usage-based charge from which the RRBs will be repaid (the "RRB
Charge");

          (ii)  approve CL&P's formation of one or more special purpose
entities (each, an "SPE"), the capitalization of each SPE by CL&P, and the
sale by CL&P to an SPE of Transition Property;

          (iii)  approve the issuance of notes by each SPE (the "SPE Debt
Securities") and the pledging by each SPE of all of its interest in the
Transition Property, and certain other collateral, to secure the SPE Debt
Securities;

          (iv  approve the issuance of RRBs by a special purpose trust
authorized and created by the Office of the State Treasurer (referred to
herein and in the Securitization Statute as the "Finance Authority"), which
RRBs shall evidence undivided beneficial interests in SPE Debt Securities;

          (v)  provide for the periodic adjustment of the RRB Charge via a
true-up mechanism;

          (vi)  approve the general structure of the RRB Transaction and
terms of the SPE Debt Securities and the RRBs, including the proposed use of
proceeds;

         (vii)  approve the servicing of the RRB Charge by CL&P, as the
initial servicer for the Transition Property, or any successor servicer,
under a servicing agreement; and

         (viii)  declare the Financing Order irrevocable as provided in Conn.
Gen. Stat. Section 16-245i(b)(1).

I.  Overview

     Securitization is the financing of a specific asset or pool of assets,
through the issuance of securities, frequently referred to as "asset-backed
securities."  For debt service and repayment of principal, these securities
rely solely on the revenue stream underlying the asset or pool of assets and,
as a result, their ratings are dependent upon the predictability or
volatility of that associated cash flow.

     The Securitization Statute permits the securitization of certain
stranded costs (the "Eligible Stranded Costs") and grants the Department the
authority to review a securitization application and issue a financing order
for the recovery of such costs.  The financing order becomes effective only
when the applicant files with the Department its written consent to all the
terms and conditions contained therein.

     In its order dated July 7, 1999 in Docket No. 99-02-05 (the "Stranded
Cost Decision"), the Department approved approximately $3.6 billion as the
total amount of CL&P's stranded costs.  At the time of the Stranded Cost
Decision, the costs of certain mitigation efforts, such as the buyout/buydown
of independent power producer ("IPP") contracts, as well as the cost of
retiring capital, were not yet quantifiable and, therefore, were not
considered.

     In its order dated October 1, 1999 in Docket No. 99-03-36 (the "Standard
Offer Decision"), the Department determined that certain Eligible Stranded
Costs of CL&P qualify for recovery through the issuance of RRBs.  CL&P is now
applying to the Department for a Financing Order approving the issuance of
RRBs in the aggregate principal amount of approximately $1.436 billion and
related transactions pursuant to the terms of the Securitization Statute.

     CL&P understands that the Department has, to date, only approved a
portion of its Eligible Stranded Costs as qualifying for securitization.  To
the extent that additional amounts, such as the IPP contracts, are approved
in other dockets, CL&P wants to make sure that the Department has all the
necessary information to approve the subsequent securitization of the full
$1.436 billion.

II.   Description of Proposed RRB Transaction

     CL&P's right to collect the RRB Charge is irrevocable, pursuant to Conn.
Gen. Stat. Section 16-245i(b)(1), and the charge itself is non-bypassable to
CL&P's customers.  The Transition Property is the asset underlying the RRBs
and represents the right to collect the total amount of RRB Charges
calculated over the life of the RRBs, together with certain other rights and
related costs.

     CL&P will form one or more bankruptcy-remote SPEs, each of which is
expected to be a Delaware limited liability company wholly-owned by CL&P and
authorized to acquire Transition Property and to issue SPE Debt Securities.
Each such SPE will constitute a "financing entity" for purposes of the
Securitization Statute.  CL&P will capitalize each SPE in an amount
anticipated to be at least 0.50% of the initial principal balance of RRBs
issued with respect to that SPE.

     CL&P will sell all of its rights in the Transition Property to one or
more SPEs in transactions each of which under Conn. Gen. Stat.   16-245k(h)
will be treated as a legal true sale and absolute transfer to such SPE.

     The SPE will issue and sell SPE Debt Securities to a special purpose
trust established by the Finance Authority.

     All of the assets of such SPE, specifically the Transition Property and
other specified collateral, will be pledged as collateral to secure the SPE
Debt Securities.

     The special purpose trust, constituting a "financing entity" under the
Securitization Statute, will issue and sell the RRBs, which will represent
undivided beneficial interests in the SPE Debt Securities and any hedging
agreement entered into in connection with the transaction.  The RRBs will be
payable solely from cashflows associated with Transition Property, primarily
the RRB Charge.  The proceeds from the sale of the RRBs, net of any
transaction expenses, will be remitted to the SPE as consideration for the
SPE Debt Securities and, ultimately, net of any remaining transaction
expenses, remitted to CL&P as consideration for the Transition Property.

     The Finance Authority shall have oversight over the terms and conditions
of the RRB issuance.

     The RRB Charge will be adjusted, up or down, pursuant to an RRB Charge
true-up mechanism.

     CL&P expects to use the proceeds from the issuance of the RRBs to pay
for transaction costs, to reduce capitalization, and to pay call and tender
premiums and refinancing costs associated therewith.

III.    Exhibits

The following exhibits are filed with this Application:

1.  The testimony of Richard A. Soderman, Director of Regulatory Policy and
Planning for Northeast Utilities Service Company.

2.  The testimony of Randy A. Shoop, Treasurer of The Connecticut Light and
Power Company.

3.  The testimony of Mark A. Englander, Senior Financial Analyst in the
Finance Group of Northeast Utilities System's Treasury Department.

4.  Proposed Transaction Description, Findings, and Orders and Approvals To
Be Included in Financing Order.

IV.  Additional Information

1.	The exact legal name of the applicant and its principal place of
business is:

The Connecticut Light and Power Company
107 Selden Street
Berlin, CT  06037

CL&P is a corporation organized and existing under the laws of the State
of Connecticut.

2.	The name, title, address and telephone number of the attorneys and other
persons to whom correspondence or communication in regard to this application
are to be addressed:

A.  Randy A. Shoop
Treasurer
The Connecticut Light and Power Company
P.O. Box 270
Hartford, CT  06141-0270
Telephone:  (860) 665-3258
Fax:  (860) 665-5457

B.  Daniel P. Venora, Esq.
Associate General Counsel
Northeast Utilities Service Company
P.O. Box 270
Hartford, CT  06141-0270
Telephone:  (860) 665-3395
Fax:  (860) 665-5504

C.  Duncan D. McCory
Senior Regulatory Planning Analyst
Northeast Utilities Service Company
P.O. Box 270
Hartford, CT 06141-0270
Telephone:  (860) 665-5726
Fax:  (860) 665-3314

D.  Richard J. Wasserman, Esq.
Day, Berry &Howard LLP
CityPlace I
Hartford, CT 06103-3499
Telephone:  (860) 275-0142
Fax: (860) 275-0343

Please contact Daniel P. Venora, Esq., Associate General Counsel, Northeast
Utilities Service Company (860-665-3395), if there are any questions with
respect to this filing.

Very truly yours,

THE CONNECTICUT LIGHT AND POWER COMPANY

By:/s/Randy A. Shoop
Treasurer

EX-99.2

                                                      EXHIBIT D 2.1



COMMONWEALTH OF MASSACHUSETTS
              DEPARTMENT OF TELECOMMUNICATIONS AND ENERGY

                                      )
Western Massachusetts Electric Company)      D.T.E. 00-40
                                      )


         PETITION OF WESTERN MASSACHUSETTS ELECTRIC COMPANY
       FOR APPROVAL OF THE ISSUANCE OF ELECTRIC RATE REDUCTION
       BONDS PURSUANT TO GENERAL LAWS CHAPTER 164, Section 1H.


I.   INTRODUCTION

1.  Western Massachusetts Electric Company ("WMECO"), an electric company
duly organized and existing under the laws of the Commonwealth of
Massachusetts, hereby petitions the Department of Telecommunications and
Energy (the "Department") for a financing order (FN 1) ("Financing Order")
approving the issuance of electric rate reduction bonds (FN 2) ("RRBs") and
related transactions, pursuant to General Laws Chapter 164, Sections lG and
1H, and the Department's orders dated September 17, 1999 and December 20,
1999 in D.T.E. 97-120 (collectively, the "Restructuring Order").  WMECO
proposes that the Financing Order, among other things: (i) identify the
portion of the transition charge (FN 3) approved by the Department in the
Restructuring Order ("Transition Charge") and related costs that may be
securitized (FN 4) (such portion of the Transition Charge, once securitized,
is referred to as the "RTC Charge"); (ii) approve the organization and
capitalization of one or more special purpose entities (each, an "SPE") to
which "transition property (FN 5) ("Transition Property") will be sold; (iii)
establish as Transition Property the RTC Charge from which RRBs will be
repaid and approve the adjustment from time to time of the RTC Charge;  (iv)
approve the servicing of the Transition Property by WMECO, as initial
servicer for the Transition Property, or any successor servicer ("Servicer"),
under a servicing agreement (the "Servicing Agreement"); and (v) grant WMECO
certain exemptions from competitive bidding and par value debt issuance
requirements.  WMECO's proposed Appendix 1 to the Financing Order ("Proposed
Financing Order Appendix") is appended to this filing as Exhibit WM-1.

2.  In support of this Petition, WMECO appends the following exhibits:

Exhibit WM-1 - WMECO's Proposed Financing Order Appendix;

Exhibit WM-2 - Prefiled testimony of Richard A. Soderman, Director of
Regulatory Policy and Planning for Northeast Utilities Service Company and
its operating companies and affiliates, including WMECO ("Soderman
Testimony");

Exhibit WM-3 - Prefiled testimony of Randy A. Shoop, Assistant Treasurer of
WMECO and Treasurer of The Connecticut Light and Power Company ("Shoop
Testimony");

Exhibit WM-4 - Prefiled testimony of Mark A. Englander, Senior Financial
Analyst in the Finance Group of Northeast Utilities System's Treasury
Department ("Englander Testimony"); and

Exhibit WM-5 - Legal memorandum addressing WMECO's eligibility to securitize
while the divestiture of its Millstone nuclear assets is pending.

3.   WMECO is eligible to participate in securitization because it has
complied with the requirements of G.L. c. 164, Section 1G(d)(4), by: (i)
fully mitigating its transition costs, as recognized by the Restructuring
Order (see Soderman Testimony); (ii) safeguarding the positions of
nonmanagerial employees at divested generation facilities (see Soderman
Testimony); (iii) proving that savings to ratepayers will result from
securitization and ensuring that all savings from securitization will inure
to the benefit of ratepayers (see Soderman Testimony); (iv) establishing an
order of preference for the use of bond proceeds such that transition costs
having the greatest impact on customer rates will be the first to be reduced
by those proceeds (see Shoop Testimony and Soderman Testimony).  (FN 6) In
addition to meeting the criteria set forth in Section 1G(d)(4), and as
requested by the Department, WMECO is also submitting herewith as Exhibit WM-
5 a legal memorandum explaining WMECO's eligibility to participate in
securitization while the divestiture of its Millstone nuclear assets is
pending.

II.   SUMMARY OF KEY TESTIMONY REGARDING CONSUMER BENEFIT

4.  If implemented as described herein and in the accompanying supporting
documents, WMECO expects securitization to result in approximately $19
million in net present value savings to WMECO's customers.  All such savings
will inure to the benefit of WMECO's customers.  See Soderman and Shoop
Testimony.  As described in the Shoop Testimony, WMECO expects to apply the
net proceeds to retire debt and equity, thereby eliminating interest
expense, preferred stock expense and equity return.  WMECO also expects to
apply the net proceeds to the buyout of a power contract.

III.   DESCRIPTION OF PROPOSED RRB TRANSACTION

5.  The procedure by which WMECO proposes to securitize a portion of its
approved transition costs is  set forth fully in WMECO's proposed financing
order and in the Englander Testimony.  The procedure is summarized below.

6.  WMECO has been working with the Massachusetts Development Finance Agency
and Massachusetts Health and Educational Facilities Authority (together, the
"Agencies") to develop the structure for the proposed securitization and the
process for approval by the Department.  Representatives of the Agencies have
reviewed and commented on this Petition and the exhibits thereto, including
the Proposed Financing Order Appendix  (Exhibit WM-1).  Based on their
knowledge and experience with other rate reduction bond financings,
representatives of the Agencies have indicated that the proposed transaction
satisfies (A) all requirements under Sections 1G and 1H relating to the terms
and conditions of the RRBs and (B) historic rating agency criteria consistent
with achieving the highest possible ratings for RRBs.

7.  In the Restructuring Order, the Department determined that certain
generation-related costs were Transition Costs.  Together with the cost of
issuance, ongoing costs (including credit enhancement, trustee, service and
other financing entity or other fees), and the estimated tax liabilities
associated with the transaction, these amounts are eligible for recovery
through the issuance of RRBs and the collection of the RTC Charge.

8.  RRBs will thus be issued to securitize a portion of WMECO's Transition
Costs approved in the Restructuring Order, together with the related
transaction and credit enhancement costs (including an overcollateralization
account and liquidity reserves, if any).  WMECO currently estimates that the
initial principal amount of RRBs to be issued will be approximately $261
million, subject to adjustments based on, without limitation, prevailing
market conditions at the time the RRBs are priced, input from nationally
recognized statistical rating organizations selected to rate the RRBs by
WMECO (with the approval of the Agencies, tax authorities, and underwriters)
and possible changes in the proposed transaction not now anticipated by
WMECO.

9.  The issuance of RRBs will reduce the carrying charge associated with
WMECO's Transition Costs that are securitized.  By reducing this charge,
WMECO customers will realize approximately $19 million in net present value
savings, reflected in lower Transition Costs over the life of the RRBs than
otherwise would be required if the transaction is not approved.

10.  WMECO will create one or more wholly-owned SPEs.  Each SPE will be
bankruptcy-remote, in that its activities will be limited to ownership of the
Transition Property and issuance of notes ("SPE Debt Securities"), and
restrictions will be imposed on its ability to commence a bankruptcy case or
other insolvency proceeding.  WMECO will capitalize each SPE in an amount
anticipated to be approximately 0.50% of the initial principal balance of the
RRBs, as may be adjusted at the time of issuance, based on tax authority or
rating agency requirements.  Such funds will be used to pay debt service and
related fees and expenses in the event of a shortfall in RTC Charge
collections.

11.  WMECO will sell all of its rights in the Transition Property to an SPE
in a transaction that, under Section 1H(f)(1), will be intended and treated
as a legal true sale and absolute transfer to such SPE notwithstanding any
contrary treatment of such transfer for accounting, tax or other purposes.

12.  Pursuant to G.L. c. 164, Section 1H(e), upon the effective date of the
Financing Order there shall exist a statutory first priority lien on all
Transition Property then existing or thereafter arising pursuant to the terms
of the Financing Order.  Such lien shall secure all obligations, then
existing or subsequently arising, to the holders of RRBs, the trustee or
representative for such holders, each SPE and special purpose trust (FN 7)
and shall arise by operation of law automatically without any action on the
part of WMECO or any other person.

13.  The SPE will then issue SPE Debt Securities to a special purpose trust
established by the Agencies.  SPE Debt Securities will be non-recourse to
WMECO and its assets, secured by all of the assets of such SPE, including
without limitation: (i) all of the SPE's interest in the Transition Property;
(ii) the rights of such SPE under the transaction documents including the
purchase agreement by which such SPE acquires the Transition Property, the
Servicing Agreement and an administration agreement; (iii) the collection
account and any other account of such SPE contained in such SPE's collection
account, including an overcollateralization subaccount and reserve
subaccount; (iv) any investment earnings on amounts held by such SPE (but
excluding an amount equal to investment earnings on the initial capital
contributed by WMECO, which earnings are to be returned to WMECO semiannually
or more frequently as a distribution of capital by such SPE so long as there
are sufficient moneys available to make scheduled distributions or interest
and principal on the RRBs and pay required financing expenses); and (v) the
capital of such SPE.  The interest rate, term, classes, and other
characteristics of the SPE Debt Securities will be determined at the time of
issuance based on then-current market conditions.

14.  RRBs, issued by the special purpose trust, are expected to be pass-
through certificates representing undivided beneficial interests in the SPE
Debt Securities.  The trustee of the special purpose trust will transfer the
proceeds it receives from the issuance of the RRBs to the SPE as
consideration for SPE Debt Securities, and the SPE will then transfer such
proceeds to WMECO as consideration for the Transition Property.

15.  RRBs will not be obligations of WMECO nor will they be secured by a
pledge of the general credit, full faith or taxing power of the Commonwealth
or any agency or subdivision of the Commonwealth in accordance with Section
1H(b) (4).  RRBs will be repaid through the collection of the RTC Charge from
each WMECO customer or ratepayer taking the delivery, transmission,
distribution, back-up, maintenance, emergency and any other delivery or
energy service provided by WMECO to such customer within the territory in
which it serves customers, regardless of that customer's source of electric
power (referred to herein as the "Retail Customer").  The RTC Charge will be
collected by WMECO or any successor distribution companies, which may include
third party suppliers or successor servicers.  The RTC Charge will be a
usage-based component of the Transition Charge on each Retail Customer's
monthly bill and may include in the future any exit fee collected pursuant to
Section 1G(g) until the RRBs, together with all interest, fees, costs and
expenses, are paid in full.  While not separately identified on each retail
user's monthly bill, each monthly bill will note that part of the Transition
Charge is owned by the SPE

16.  Section 1H(b)(3) provides that the Financing Order and the RTC Charge
shall be irrevocable, and the Department (or any successor thereto) shall not
have authority to revalue or revise for ratemaking purposes the Transition
Costs, or determine that the Transition Costs or the RTC Charge are unjust or
unreasonable, or in any way reduce or impair the value of the Transition
Property either directly or indirectly by taking into account the Transition
Costs when setting rates for WMECO, nor are the amount of revenues arising
with respect thereto subject to reduction, impairment, postponement or
termination.

17.  Prior to the issuance of the RRBs, WMECO will file an initial RTC Charge
in an "Issuance Advice Letter" setting forth the final terms of the RRBs.
Both initially and during the life of the RRBs, the RTC Charge will be
calculated and set at a level intended to recover: (i) the principal balance
of (in accordance with the expected amortization schedule), and interest on,
the SPE Debt Securities authorized under the Financing Order; (ii) the costs
of servicing the SPE Debt Securities and the RRBs, including the Servicing
Fee, the Administration Fee, fees for the trustees, rating agency fees, legal
and accounting fees, managers'/directors' fees, contingent indemnity
obligations in the RRB transaction documents, other fees and expenses; and
(iii) the cost of creating and maintaining any credit enhancement required
for the SPE Debt Securities and the RRBs (other than credit enhancement
obtained because WMECO is making RTC Charge remittances less frequently than
daily).

18.  The level of RTC Charge may differ for specified periods during the term
of the RRBs due to several factors, including the nature of the amortization
schedule, changes in the principal balance of RRBs, changes in the weighted
average interest cost of RRBs as the relative principal balance outstanding
changes, the impact of the variability of energy sales, changes in payment
and charge-off patterns, and changes in ongoing fees, costs and expenses of
RRBs.

19.  In order to minimize the impact of variability in energy sales, changes
in payment and charge-off patterns, collections on the payment of principal,
interest, fees, costs, and expenses on RRBs and the maintenance of credit
enhancement, and to maintain actual principal amortization in accordance with
the expected amortization schedule, WMECO proposes to adjust the RTC Charge,
up or down, pursuant to an RTC Charge adjustment mechanism in accordance with
Section 1H(b) (5) and the methodology described in an Appendix B to the
Proposed Financing Order Appendix (Exhibit WM-1).

20.  Through the sale of the related Transition Property to an SPE, such SPE
will obtain the right and the obligation to assess and collect the RTC
Charge.  On behalf of such SPE, WMECO will initially act as the Servicer for
the transition property, although a successor Servicer may perform these
functions in the future.  Any successor Servicer will have the same rights
and obligations with respect to the RTC Charge as WMECO as initial Servicer
under the Financing Order and Sections 1G and 1H.   WMECO, or any successor
Servicer, will be responsible for calculating, billing, collecting, and
remitting the RTC Charge from all Retail Customers.  WMECO will carry out
billing and collection activities both as Servicer with respect to the RTC
Charge - on behalf of the SPE and the RRB holders - and as principal with
respect to its own charges to be paid by such customers.  In consideration of
its servicing responsibilities, WMECO or any successor Servicer will receive
a periodic servicing fee that will be recovered through the RTC Charge as
described  in Exhibit WM-1.

21.  WMECO expects to implement, with the Department's guidance and approval,
certain policies and procedures designed to ensure that the credit ratings of
RRBs will not be downgraded or withdrawn due to the existence of any third
party supplier.  The policies and procedures described in the Englander
Testimony will help retain the quality of RTC Charge billings, collections,
and remittances.

IV.   SEC APPROVAL

22.  WMECO is subject to the jurisdiction of the Securities and Exchange
Commission ("SEC") under the Public Utility Holding Company Act of 1935, as
amended.  WMECO will file an Application/Declaration on Form U-1 with the SEC
for approval of the proposed transaction.

V.   SERVICE

23.  Please include the following on the service list for all correspondence
in this proceeding:

Stephen Klionsky, Esq.
Western Massachusetts Electric Company
260 Franklin Street, 21st Floor
Boston, Massachusetts 02110
Tel.  617/345-4778
Facsimile  617/345-4780
e-mail  klionsh@nu.com

Jay E. Gruber, Esq.
Janet M. Zipin, Esq.
Palmer & Dodge LLP
One Beacon Street
Boston, Massachusetts 02108
Tel. 617/573-0449
Facsimile 617/227-4420
e-mail  jgruber@palmerdodge.com

Anne Bartosewicz
Manager, Regulatory Planning
Northeast Utilities Service Company
P.O. Box 270
Hartford, Connecticut  06141-0270
Tel.  860/665-3213

WHEREFORE, pursuant to General Laws, Chapter 164, Sections 1G and 1H, WMECO
respectfully requests the Department:

A.   Grant any and all authorizations that may be required under
Massachusetts law, including without limitation approval and authorization in
the Financing Order pursuant to Sections 1G and 1H and the Restructuring
Order, for the consummation of the transactions contemplated by the issuance
of RRBs and related matters, including without limitation:  (i) the
identification of the portion of the Transition Charge (i.e., the RTC Charge)
that may be securitized through the issuance of RRBs, (ii) the organization
and capitalization of each SPE to which the Transition Property will be sold,
(iii) the establishment as Transition Property and adjustment from time to
time of the RTC Charge from which RRBs to be issued will be repaid, (iv) the
issuance by each SPE of SPE Debt Securities and the pledging by each SPE of
all of its interest in the Transition Property, and certain other collateral,
to secure the SPE Debt Securities, and (v) the servicing of the RTC Charge by
WMECO, as initial Servicer for the Transition Property, or any successor
Servicer under the Servicing Agreement.

B.   Find an exemption in the public interest from each of (i) the
competitive bidding requirements of G.L. c. 164, Section 15, and (ii) the par
value debt issuance requirements of G.L. c. 164 Section 15A, in connection
with the issuance of RRBs and to grant each such exemption.

C.   Find that savings inure to WMECO's customers, reflected in lower
transition costs to WMECO's Retail Customers over the life of the RRBs than
would otherwise be required to recover the approved transition costs had the
transaction not been approved in accordance with Sections 1G(d)(4) and
1H(b)(2).

D.   Make such other findings and issue such other orders as set forth in the
Proposed Financing Order Appendix attached hereto as Exhibit WM-1.

E.   Grant such other and further orders and approvals as the Department may
deem necessary or proper in the circumstances.

Respectfully submitted,

WESTERN MASSACHUSETTS ELECTRIC COMPANY

By Its Attorney

Stephen Klionsky
260 Franklin Street, 21st Floor
Boston, Massachusetts 02110
Tel. 617/345-4778
Facsimile 617/345-4780
e-mail klionsh@nu.com

Dated:  April  18, 2000


Footnotes:

(1)  "Financing order" is defined as "an order of the department adopted in
accordance with [G.L. c.164, Section 1H] approving a plan, which shall
include, without limitation, a procedure to review and approve periodic
adjustments to transition charges to include recovery of principal and
interest and costs of issuing, servicing, and retiring electric rate
reduction bonds contemplated by the financing order."  G.L. c.164, Section
1H(a).  G.L. c.164, Sections lG and 1H are hereinafter referred to as
"Section lG" and "Section 1H", respectively.

(2)  "Electric rate reduction bonds" are defined as "bonds, notes,
certificates of participation or beneficial interest, or other evidences of
indebtedness or ownership, issued pursuant to an executed indenture,
financing document, or other agreement of the financing entity, secured by or
payable from transition property, the proceeds of which are used to provide,
recover, finance, or refinance transition costs or to acquire transition
property and that are secured by or payable from transition property."
Section 1H(a).

(3)  "Transition charge" is defined as "the charge to the customers which
provides the mechanism for the recovery of an electric company's transition
costs." Section 1H(a).  "Transition costs" are defined as "the costs
determined pursuant to section 1G which remain after accounting for maximum
possible mitigation, subject to determination by the department." Section
1H(a).

(4)  "Securitized" and "securitization" are used herein to refer to the
"securitization" contemplated by Sections 1G and 1H.

(5)  "Transition Property" is defined as "the property right created pursuant
to [G.L. c. 164 Section 1H], including, without limitation, the right, title,
and interest of an electric company or a financing entity to all revenues,
collections, claims, payments, money, or proceeds of or arising from or
constituting reimbursable transition costs amounts which are the subject of a
financing order, including those non-bypassable rates and other charges that
are authorized by the department in the financing order to recover transition
costs and the costs of providing, recovering, financing, or refinancing the
transition costs, including the costs of issuing, servicing, and retiring
electric rate reduction bonds."  Section 1H (a).    "Reimbursable transition
costs amounts"  are defined as "the total amount authorized by the department
in a financing order to be collected through the transition charge, as
defined pursuant to section 1 [of G.L. c.164], and allocated to an electric
company in accordance with a financing order."

(6)  In addition, pursuant to G.L. c. 59, Section 38H(c),  the Department
cannot approve an application for securitization if a company owns, as of
July 1, 1997, a nuclear generation facility located in the Commonwealth
unless the company has executed a tax agreement with the plant's host
community.  WMECO does not own such a facility and the provision is thus
inapplicable (see Soderman Testimony).

(7)  "Special purpose trust" is defined to mean "any trust, partnership,
limited partnership, association, corporation, nonprofit corporation, limited
liability company, or other entity established and authorized by the agency
and the authority to acquire transition property or to issue rate reduction
bonds, or both, subject to approvals by the agency and the authority and the
powers of the agency and the authority as provided by the agency and the
authority in their resolutions authorizing the entities to issue rate
reduction bonds."  Section 1H(a).

EX-99.3

                     Public Utilities Commission


                             DE 99-099


                          PSNH  Proposed
                      Restructuring Settlement


                         Order No. 23,443

                          April 19, 2000








                      Douglas L. Patch, Chairman
                      Susan S. Geiger, Commissioner
                      Nancy Brockway, Commissioner







                           TABLE OF CONTENTS

I.   INTRODUCTION

II.   BACKGROUND

III.   PROCEDURAL HISTORY

IV.   SUMMARY OF THE SETTLEMENT AGREEMENT:

V.   POSITIONS OF THE NON-SETTLING PARTIES AND NON-SETTLING STAFF-Generally36

A.   Representative Jeb Bradley
B.   Representative Gary Gilmore
C.   THINK - New Hampshire
D.   Business and Industry Association of New Hampshire
E.   Cabletron Systems, Inc.
F.   Great Bay Power Company
G.   PJA Energy Systems Design
H.   Office of Consumer Advocate
I.   New England Power Co. & Granite State Electric Co.
J.   City of Manchester
K.   Seacoast Anti-Pollution League
L.   Conservation Law Foundation
M.   Save Our Homes Organization/Community Action Programs
N.   Campaign for Ratepayers' Rights
P.   New Hampshire Consumers Utility Cooperative
Q.   Staff Advocates

VI.   POSITIONS OF NON-SETTLING PARTIES BY ISSUE

A.   BENCHMARKING
1.   Parties other than Staff
2.   Staff Advocates And Non-settling Staff
B.   RECOVERY OF STRANDED COSTS
1.   Parties other than Staff
2.   Staff Advocates and Non-Settling Staff
C.   DIVESTITURE AND AUCTION
1.   Parties other than Staff
2.   Staff Advocates and Non-Settling Staff
D.   TRANSITION SERVICE
1.   Parties other than Staff
2.   Staff Advocates and Non-Settling Staff
E.   SECURITIZATION
1.   Parties other than Staff
F.   NU MERGER WITH CONSOLIDATED EDISON
1.   Parties other than Staff
G.   ENVIRONMENT AND SYSTEM BENEFITS
1.   Parties other than Staff
H.   RECLASSIFICATION OF TRANSMISSION AND DISTRIBUTION ASSETS
1.   Parties other than Staff
I.   COST ALLOCATION AND RATE DESIGN
1.   Parties other than Staff

VII.   POSITIONS OF THE SETTLING PARTIES:127

A.   Settling Staff and Governor's Office of Energy and Community Services 7
Recovery of Stranded Costs
Transition Service and Rates
Transmission and Distribution Service and Rates
Rate Design
Securitization
Northeast Utilities/Consolidated Edison Merger
Divestiture and Auction
Environment and Energy Efficiency
Benchmarking
Other Issues

B.   Public Service Company of New Hampshire
Recovery of Stranded Costs
Transition Service and Rates
Transmission and Distribution Service and Rates
Rate Design
Securitization
Merger
Divestiture and Auction
Environment and Energy Efficiency
Benchmarking
Rate Agreement as Contract
Great Bay Power Corp.
Return on Equity
Millstone 3
Loan Fund
Seabrook Divestiture
Transmission and Distribution

VIII.   COMMISSION ANALYSIS

A.   AUTHORITY TO CONSIDER SETTLEMENT
B.   STANDARD OF REVIEW
C.   BENCHMARKING ANALYSIS
1.   Settlement Agreement Rate Path
2.   "Business As Usual" Rate Path
a.   Docket DR 97-059:  Base Rate Reductions
b.   Systems Benefits Charge Comparability
c.   "Other Dockets" Adjustment
d.   FPPAC Undercollection Offset By Base Rate Reconciliation
e.   Projected FPPAC Increase
f.   Termination Of Seabrook Deferred Return
g.   Acquisition Premium, SPP "Step Adjustment" and T&D Rates
3.   Period Of Comparison
4.   Benchmarking Results
D.   APPLICATION OF THE PUBLIC INTEREST STANDARD
E.   CHANGES REQUIRED TO ACHIEVE THE PUBLIC INTEREST
1.   Rebalancing The Risks And Benefits Of The Settlement Agreement
2.   Specific Changes Required In The Settlement Agreement
F.   ADJUSTMENTS TO STRANDED COST RECOVERY
1.   Accumulated Deferred Income Taxes (ADIT)
2.   Seabrook Sale
3.   Regulatory Liabilities
4.   Hydro-Quebec Support Payments
5.   Reconciliation and Recalculation of the SCRC
a.   NOx Credits
b.   Loss On Reacquired Debt
c.   Updating Of The FPPAC Deferral
6.   Recovery End Date "Cushion"
G.   SECURITIZATION OF STRANDED ASSETS
1.   Overview
2.   The Mix of Assets Being Securitized
3.   Analysis
H.   STRANDED COST RECOVERY CHARGE
1.   Overview
2.   Analysis And Findings
I.   TRANSITION SERVICE
1.   Transition Service Price
2.   Retail Adder
3.   One Transition Service Rate
4.   Use of Existing Resources
5.   Transition Service Bidding
J.   DELIVERY SERVICE RATE
K.   CONSOLIDATED EDISON/NORTHEAST UTILITIES MERGER
L.   ASSET DIVESTITURE
1.   Affiliate Bidding, Role Of Independent Consultant, PUC Oversight
2.   Timing Of Asset Divestiture, Separate Fossil And Hydro Auctions And
Linking Asset Bids To Bids For Transition Service
3.   Details Of Fossil Auction
4.   Divestiture And Market Power Considerations
M.   MUNICIPAL PARTICIPATION IN AUCTION AND PROCEEDS FROM SALE OF GARVINS
FALLS LAND
N.   NUCLEAR DECOMMISSIONING
1.   Collection Of PSNH's Seabrook Decommissioning Responsibility
2.   Great Bay's Seabrook Decommissioning Proposal
O.   RATE DESIGN
1.   Overview
2.   Specific Rate Calculations - First Year
3.   Specific Rate Design Proposals
a.   Delivery Service Tariff - Overall Structure
b.   Delivery Service Tariff - Recovery Of Costs
c.   Delivery Service Tariff - Changes Allowed Or Required By Proposed
Agreement

(1)   Flat Residential Cents Per kWh Rates
(2)   Transition Between General Service Rates
(3)   Partial Or No Reduction To Certain Optional Rates
d.     Delivery Service Tariff - Changes Neither Required Nor Prohibited
Under Proposed Agreement
(1)     Elimination Of Elderly Discount
(2)     Elimination Of Targeted Lifeline Rate
(3)     Unbundling Outdoor Lighting Rates Using Actual Monthly Usage
(4)     Elimination of NEPOOL Type 5 Interruptible Service Rate
(5)     Closure Of ED, BR And LR Rates
e.     Unbundling Of Transmission And Distribution Rates
f.     Other Fees And Charges
(1)     Residential Late Payment Charge And New Or Increased Service Charges
(2)     Line Extensions
g.     Terms And Conditions For Suppliers
h.     Special Contracts
P.     OTHER MATTERS
1.     PSNH/NHEC Settlement
2.     Systems Benefits Charge
3.     Environmental Issues
4.     Millstone 3
5.     Depreciation
6.     Small Power Producers
7.     Settlement Agreement Language Regarding Binding Effect Of Commission
Approval
8.     Resumption Of Dividends
9.     Notification By Settling Parties In Response To Commission
Modification
10.     Summary of Estimated Rate Effects of Order
Q.     CONDITIONS TO SETTLEMENT AGREEMENT
1.     Amendments to Stranded Cost Recovery
2.     Transition Service
3.     Securitization
4.     Stranded Cost Recovery Charge
5.     Proposed ConEd/NU "Merger"
6.     Asset Divestiture
7.     Municipal Participation in Auction and Proceeds from Sale of Garvins
Falls Land
8.     Nuclear Decommissioning
9.     Rate Design
10.     Other Issues
Glossary of Acronyms Used in this Order













                                DE 99-099

                 Public Service Company of New Hampshire

                     Proposed Restructuring Settlement

              Order Approving Settlement with Modifications

                        O R D E R   N O.  23,443


     APPEARANCES:  Robert A. Bersak, Esq., Gerald M. Eaton, Esq. and Sulloway
& Hollis by Martin L. Gross, Esq. for Public Service Co. Of New Hampshire;
Foley, Hoag & Eliot, LLP by James K. Brown, Esq., Stephen J. Judge, Esq. and
Wynn E. Arnold, Esq. of the New Hampshire Attorney General's Office for the
Governor of New Hampshire, the Governor's Office of Energy and Community
Services and the New Hampshire Attorney General; Mark W. Dean, Esq. of Dean,
Rice & Kane, for New Hampshire Electric Cooperative; Seth Shortlidge, Esq.
and Lisa Shapiro of Gallagher, Callahan & Gartrell, for Wausau Papers; Rep.
Jeb Bradley, member of the Legislature, pro se; Rep. Gary Gilmore, member of
the Legislature, pro se; Connie Rakowsky, Esq. of Orr & Reno P.A. for the
Granite State Hydro Association and individual hydroelectric facilities;
David W. Marshall, Esq. for the Conservation Law Foundation; John Ryan, Esq.
for the Community Action Program; Alan Linder, Esq. of New Hampshire Legal
Assistance, for the Save Our Homes Organization; James Rubens for THINK - New
Hampshire; Pentti Aalto for PJA Energy Systems Designs; Peter H. Grills, Esq.
and Elizabeth I. Goodpaster, Esq. of O'Neill, Grills & O'Neill, for the City
of Manchester; Susan Chamberlin, Esq. of Donahue, Tucker & Ciandella, for the
City of Concord; Carlos A. Gavilondo, Esq. for Granite State Electric/New
England Power Company; Robert A. Olson, Esq. Of Brown, Olson, and Wilson
representing six woodfired power plants; Steven, V. Camerino, Esq. of McLane,
Graf, Raulerson & Middleton, for Great Bay Power Corp. and the City of
Claremont; Timothy W. Fortier for the Business & Industry Association of
N.H.; James A. Monahan and Andrew Weissman, Esq. of Morrison & Foerster,
L.L.P. for Cabletron Systems, Inc.; Joshua L. Gordon, Esq. and Robert A.
Backus, Esq. For the Campaign for Ratepayers' Rights; Robert Upton II, Esq.
of Upton, Sanders & Smith for the Towns of Bow, New Hampton, Gorham,
Hillsboro and Franklin; Robert P. Cheney, Jr., Esq. of Sheehan Phinney Bass +
Green P.A. representing JacPac Foods, Ltd.; Mary Metcalf for Seacoast Anti-
Pollution League; James T. Rodier, Esq. for Consumers Utility Service
Cooperative and Freedom Partners, LLC; Michael W. Holmes, Esq. and Kenneth
Traum of the Office of Consumer Advocate representing Residential Ratepayers;
John E. McCaffrey, Esq. of Morrison & Hecker, LLP for PUC Staff advocates;
Lynmarie Cusack, Esq. of the NH Public Utilities Commission for PUC
Settlement Staff, and Larry Eckhaus, Esq. for the Staff of the New Hampshire
Public Utilities Commission.

I.   INTRODUCTION

     This docket concerns a comprehensive proposal designed to resolve the
outstanding issues surrounding the restructuring of the state's largest
electric utility, Public Service Company of New Hampshire (PSNH), pursuant to
the Electric Utility Restructuring Act, RSA 374-F and its mandate for retail
competition in the sale of electricity.  The proposal takes the form of a
Settlement Agreement that is intended to conclude the ongoing federal
litigation between PSNH and the Commission over restructuring issues and to
resolve numerous open dockets that concern related subjects.

II.   BACKGROUND

     We believe it is helpful to begin by placing this proceeding in
historical context.  In large part, the issues before us are a direct
outgrowth of PSNH's 1988 decision to seek bankruptcy protection.(FN 1)  Under
the reorganization plan confirmed by the bankruptcy court in 1990, Northeast
Utilities (NU) of Berlin, Connecticut, agreed to acquire PSNH, invest $2.3
billion in the company and assume the operation of Seabrook through another
NU subsidiary, North Atlantic Energy Corporation (NAEC).

     A key aspect of the reorganization plan was the so-called Rate
Agreement, entered into by NU and signed by the Governor and Attorney
General.  The Rate Agreement established a mechanism to permit NU to recover
certain costs associated with acquiring PSNH and Seabrook. The most prominent
features of the Rate Agreement are:  the "fixed rate period;" the acquisition
premium; and the Fuel and Purchased Power Adjustment Clause (FPPAC).  The
Rate Agreement also created a separate mechanism to permit PSNH ratepayers to
benefit from savings derived from capacity transfers and joint economic
dispatch across the combined system of NU affiliates, which also includes
Connecticut Light & Power (CL&P) and Western Massachusetts Electric Company
(WMECo).  Within the NU system, these savings were achieved via a written
Sharing Agreement between PSNH and NU and Capacity Transfer Agreements
between PSNH and NU's initial system (CL&P and WMECo).

     The rates paid by PSNH customers under the terms of the Rate Agreement
were, and remain, among the highest in the nation.  In 1996, the Legislature
adopted the Electric Utility Restructuring Act, RSA 374-F, declaring that
the most compelling reason to restructure the New Hampshire electric utility
industry is to reduce costs for all consumers of electricity by harnessing
the power of competitive markets.

RSA 374-F:1, I.  The Restructuring Act articulates a set of 15 interdependent
policy principles" intended to guide the Commission in implementing electric
industry restructuring.  RSA 374-F:1, II.  Among those principles is the
recovery of stranded costs, defined as...

costs, liabilities, and investments, such as uneconomic assets, that electric
utilities would reasonably expect to recover if the existing regulatory
structure with retail rates for the bundled provision of electric service
continued and that will not be recovered as a result of restructured industry
regulation that allows retail choice of electricity suppliers, unless a
specific mechanism for such cost recovery is provided.

RSA 374-F:2, IV.  The Legislature restricted the recovery of such stranded
costs to include only: (a) commitments existing or obligations incurred prior
to May 21, 1996 (the Act's effective date); (b) renegotiated commitments
approved by the Commission; and (c) new mandated commitments approved by the
Commission.  RSA 374-F:2,IV(a)-(c).  Another key principle in the Act is
"near term rate relief."  RSA 374-F:2, XI.  The Legislature made clear that
"[t]he goal of restructuring is to create competitive markets that are
expected to produce lower prices for all customers than would have been paid
under the [then-]current regulatory system."  Id. (FN 2)

     The Act directed the Commission to develop a statewide restructuring
plan by February 28, 1997 and to implement retail choice by requiring
jurisdictional utilities to provide unbundled, open-access delivery services
so that retail customers could purchase electricity from competing suppliers
by July 1, 1998.  RSA 374-F:4, I and II.  In addition, the Act required each
utility to submit a compliance filing by June 30, 1997, to be approved by the
Commission if the filing was in the public interest and substantially
consistent with the principles in the Act.  RSA 374-F:4, III.

     On February 28, 1997, in Docket No. DR 96-150, the Commission issued a
Statewide Electric Restructuring Plan (FN 3) and Order No.  22,512
"Addressing PSNH's Request for Interim Stranded Cost Charges." (FN 4)  On
March 3, 1997, PSNH, its parent company NU, NAEC and another NU affiliate,
Northeast Utilities Services Company (NUSCo), filed a complaint in the United
States District Court for the District of New Hampshire, challenging both the
Restructuring Plan and the Commission's interim stranded cost order (Order
No. 22,512).

     In their complaint, the plaintiffs alleged that: the 1997 Restructuring
Plan violated the Fifth and Fourteenth Amendments to the U.S. Constitution
and analogous provisions of the New Hampshire Constitution, by taking
property without just compensation;  the plan denied PSNH its constitutional
right to substantive due process;  the Commission violated the Contracts
Clause of the federal constitution by repudiating the cost-recovery
provisions of the Rate Agreement;  the plan sought to extend the Commission's
regulatory authority beyond New Hampshire in violation of the federal
constitution's Commerce Clause; and the plan effected a violation of certain
First Amendment rights enjoyed by PSNH and its affiliates.  The plaintiffs
also alleged numerous violations of federal statutes, specifically:  the
Federal Power Act, the Public Utilities Regulatory Policies Act of 1978
(PURPA) and the Public Utilities Holding Company Act.  The plaintiffs sought
and, on March 10, 1997, the Federal District Court granted, a temporary
restraining order that stayed the Commission from implementing the
restructuring plan and interim stranded cost determinations.  After a
hearing, the court determined that its grant of emergency injunctive relief
would remain in effect pending further order of the court.  See Public
Service Co. of N.H. v. Patch, 962 F. Supp. 222 (D.N.H. 1997) (also
determining that case was ripe for adjudication and that federal abstention
to permit resolution in state forums not warranted).  Although the complaint
by PSNH and its affiliates remains pending before the U.S. District Court, it
has been stayed to permit the opportunity for settlement. (FN 5)

     The District Court's grant of temporary injunctive relief to PSNH and
its affiliates effectively halted implementation by the Commission of its
statewide electric industry restructuring plan.  This occurred because as
originally enacted, RSA 374-F:4, IV precluded the Commission from requiring a
utility to implement its compliance filing until filings representing at
least 70% of the state's retail electric sales (measured in kWh per year)
were implemented or were in process of implementation.  Since PSNH serves
approximately 70% of the New Hampshire retail electric load, this provision
coupled with the stay by the District Court prevented the Commission from
requiring any utility to implement retail access.  The Legislature, however,
amended this provision in 1998; it now permits the Commission to defer
implementation of the compliance filings of utilities having less than a 50%
share of statewide electric distribution sales (measured in kWh per year)
until compliance filings representing at least 70 percent of the state's
retail electric sales are implemented or are in process of implementation.
See RSA 374-F:4, IV.

     On March 20, 1998, the Commission issued Order No. 22,875 in Docket No.
DR 96-150 amending and clarifying the statewide Restructuring Plan.  See
Electric Utility Restructuring, 83 NH PUC 126 (1998).  On June 12, 1998, the
District Court clarified that its earlier injunction did not preclude the
Commission from considering or ruling on any voluntary filings made by the
plaintiffs to implement RSA 374-F, including the filing of settlements or
submission of compliance plans.  Thereafter, the efforts to implement
statewide electric industry restructuring progressed, absent PSNH. (FN 6)

     On June 14, 1999, PSNH and NU announced they had signed a Memorandum of
Understanding (MOU), purporting to contain a framework to resolve all matters
in the federal litigation and to implement retail competition for PSNH's
customers.  In addition to PSNH and NU, signatories to the MOU included:
Governor Jeanne Shaheen; Attorney General Philip T. McLaughlin; Thomas B.
Getz, the Commission's Executive Director and Secretary; (FN 7) Deborah J.
Schachter, Director of the Governor's Office of Energy and Community Service
(GOECS).  On August 2, 1999, the signatories submitted a formal Settlement
Agreement to the Commission.

     Following the announcement of the MOU, the Legislature enacted House
Bill 464 as Chapter 289 of the 1999 Laws.  House Bill 464 explicitly
acknowledged that a Settlement Agreement was near completion.  Among other
things, it required any securitization (FN 8) proposal to be approved, first
by the Commission and then by the Legislature.  See 1999 N.H. Laws 289:3. The
Legislature required the Commission to determine whether the implementation
as part of the utility's restructuring plan will result in benefits to
customers that are substantially consistent with the principles contained in
RSA 374-F:3 and RSA 369-A:1, X and with RSA 369-A:1, XI and the extent to
which any rate reduction bonds issued pursuant to the securitization proposal
would be successfully traded at favorable rates on the existing
securitization market.

1999 N.H. Laws, 289:3, I.

     House Bill 464 makes clear that any Commission order approving the
securitization aspects of the Settlement Agreement "shall not create a
presumption of legislative consideration of, or approval of the needed
legislative authorization to use securitization."  1999 N.H. Laws, 289:3, I.
Rather, "further enabling legislation" will be required for securitization to
go into effect.  Id.

     The Legislature further mandated in House Bill 464 that participants in
the Commission's proceeding to review a settlement, provide "a basis for the
commission and Legislature to compare the settlement to other possible
outcomes."  1999 N.H. Laws, 289:4.  Accordingly, the Legislature directed the
participants to submit any relevant "testimony, exhibits, data requests and
data responses" from pending dockets relating to PSNH restructuring, its base
rates and its FPPAC rates.  Id.

III.   PROCEDURAL HISTORY

     On June 17, 1999, with the concurrence of the Governor, the Office of
the Attorney General, GOECS and the members of the Commission Staff involved
in the negotiations, PSNH submitted the MOU to the Commission and moved to
stay 12 proceedings so that the Signatories could continue to focus their
efforts on "negotiating and drafting the definitive agreement, and then, on
the proceeding before this Commission to review that agreement...."  The
Settling Parties sought to stay the following proceedings:

DR 96-150  Electric Utility Restructuring Proceeding and PSNH Interim
Stranded Cost Charge;

DR 96-148  "Best Efforts" Proceeding: to determine whether PSNH used its best
efforts to negotiate with the Independent Power Producers (IPPs);

DR 96-149  "Light Loading" Proceeding: to determine whether the Light Loading
rules of the Federal Energy Regulatory Commission (FERC) apply to PSNH
purchases from IPPs;

DR 96-424  Petition of Hannaford Brothers Company: to determine whether a
customer opting to self-generate should be required to pay system costs;

DR 97-014  PSNH Fuel and Purchased Power Adjustment Clause;

DR 98-014  PSNH Fuel and Purchased Power Adjustment Clause;

DR 98-197  PSNH Fuel and Purchased Power Adjustment Clause;

DE 99-044  PSNH Fuel and Purchased Power Adjustment Clause;

DR 97-059  PSNH Base Rate Proceeding;

DE 97-167  Petition of OCA re: Investigation into whether PSNH should have
joined the utilities that brought suit against NU in connection with its
management of the Millstone 3 nuclear power plant;

DF 97-185  PSNH Management Audit: related to the Base Rate investigation; and

DR 95-247  Bio-Energy Proceeding: regarding purchases from Bio-Energy,
Corporation, and IPP.

     Following a pre-hearing conference on August 10, 1999, the Commission
granted the motion to stay.  See Order No. 23,299 (September 16, 1999).  In
addition, the Commission announced it would employ a two-phase review of the
Settlement Agreement.  The Commission ruled that Phase I would provide the
Settling Parties the opportunity to present their agreement and supporting
evidence and allow the Commission to conduct hearings to establish a basis
for the Commission to compare the Settlement to the range of reasonable
outcomes in the other noticed dockets.  Following the Settlement proponents'
presentation of their case, the Commission would provide all parties the
opportunity to argue whether the Commission should continue hearings on the
Settlement or resume litigating the dockets affected by the Settlement.
Order 23,299 at 34-36.

     The Commission further stated that if, at the conclusion of Phase I, the
Commission determined that the Settling Parties demonstrated they had
submitted sufficient evidence upon which the Commission could decide that the
proposed Settlement Agreement is in the public interest and consistent with
all of the legislative requirements concerning electric industry
restructuring, including those contained in RSA 374-F:3, RSA 374-F:4 and Laws
of 1999, Chapters 289:3, 289:4, 289:6-8, the Commission would move to Phase
II.  In the event the Settling Parties satisfied this burden, Phase II would
permit Non-Settling Parties the opportunity to state their case.  Order
23,299 at 34-36 (September 16, 1999).  The Commission also ruled that, at the
conclusion of Phase I, it would consider whether to proceed to Phase II and,
if so, whether to resume litigation of the stayed dockets at the same time.
Order No. 23,299 at 37 (September 16, 1999).

     On June 15, 1999, two days before PSNH filed the MOU and motion to stay,
a motion was filed by several parties (FN 9) to designate Thomas B. Getz (the
Commission's Executive Director and Secretary), Michael Cannata (the
Commission's Chief Engineer) and Liberty Consulting Inc.  as "Staff
Advocates" pursuant to RSA 363:32 with regard to any docket in which the MOU
or anticipated settlement would be at issue.  In addition, the moving parties
sought such a designation for any other members of the Commission Staff who
participated, either directly or indirectly, in the negotiations concerning
the settlement proposal.  A person designated as a staff advocate is
prohibited from advising the Commission "with respect to matters at issue in
the contested case."  RSA 363:35.

     Relying on RSA 363:33, the Commission designated as "Staff Advocates"
Messrs. Getz and Cannata and all of Liberty Consulting Group with the
exception of two of its employees, Messrs. Michael McFadden and Robert
Parente, who remained undesignated and thus free to advise the Commission.
Order No. 23,299 at 21.  The Commission ruled that this designation
was for the instant proceeding only and declined at that time to designate
its staff in other proceedings the Settling Parties contended were affected
by the Settlement.  The Commission assigned Staff Attorney Lynmarie Cusack to
represent Messrs. Getz and Cannata, as well as the designated personnel from
Liberty Consulting Group, collectively referred to in this order as "Settling
Staff."  Order No. 23,299 at 21.

     As a result of designating the Commission's Executive Director and
Secretary, Thomas Getz, as "Staff Advocate," the Commission directed all
parties to address all correspondence to the Commission with respect to this
docket to Ms. Debra A.  Howland, Acting Executive Director and Secretary.  In
addition, the Commission instructed parties to specifically label all
correspondence with Commission Staff and Staff counsel as appropriate and
indicate confidentiality, as necessary, to prevent inadvertent distribution
of such material.  Order No. 23,299 at 44.

     In that same Order, the Commission noted that George McCluskey, the
Commission's Director of Restructuring, had submitted his resignation,
effective within the next month.  The Commission stated that, since Mr.
McCluskey had been designated as a "Staff Advocate" in the ISC portion of the
DR 96-150 rehearing process, the Commission had and would continue to treat
Mr. McCluskey as though he were designated in this proceeding.

     Two parties, the Office of Consumer Advocate (OCA) and Granite State
Taxpayers, Inc.(GST), filed a motion on July 21, 1999 seeking the
disqualification of Commissioner Brockway in connection with a conversation
about the timing for filing Staff Advocate testimony
that took place at the Commission offices in June 1999 involving her, Mr.
McCluskey and a member of the Commission's legal staff.  In Order No. 23,277
(August 4, 1999), Commissioner Brockway declined to disqualify herself; she
denied the OCA and GST motion for rehearing.  See Order No. 23,298 (September
13, 1999).  Pursuant to its authority under RSA 365:20, and at the request of
Commissioner Brockway, the Commission transferred the question of whether
Commissioner Brockway should be disqualified from this proceeding to the New
Hampshire Supreme Court.  The Court summarily concluded that no substantial
question of law was presented and ruled that Commissioner Brockway's denial
of the motion for recusal was neither unjust nor unreasonable.  Appeal of NH
Public Utilities Commission Re: Public Service Company of New Hampshire, No.
99-495 (New Hampshire Supreme Court, September 29, 1999).  The Court declined
to hear a later appeal of GST on the same issue.  Appeal of Granite State
Taxpayers, Inc., No. 99-616 (New Hampshire Supreme Court, December 30, 1999).

     By letter dated October 13, 1999, the Commission notified the parties
that it had requested the law firm of Morrison and Hecker to provide
assistance in the review and analysis of the Settlement Agreement.  In
addition, the Commission requested that Morrison and Hecker retain the
services of LaCapra Associates ("LaCapra"), where Mr. McCluskey was now a
senior analyst, to provide assistance in analyzing the Settlement Agreement
and alternatives offered by other parties.  Consistent with its determination
in DR 96-150, the Commission ruled that all of LaCapra, as well as Morrison
and Hecker Attorney John McCaffrey would be treated as
functioning under a staff advocate designation.  Mr. McCluskey and his
colleagues are referred to in this order as Staff Advocates.

     In Order No. 23,299, the Commission further clarified the party status
of those who were participating in this docket.  In keeping with past
Commission practice, the Settling Staff, the Non-Settling Staff and the other
Staff members participating in this proceeding would not, by virtue of that
participation, gain full party status but, rather, would be treated as though
they were parties.  The Commission determined that any party granted
intervenor status in the dockets affected by this proceeding would be treated
as intervenors here, and the Commission granted additional intervention
motions.

     The Commission conducted 14 days of Phase I hearings in late October and
early November of 1999. (FN 10)  During these hearings, 13 PSNH witnesses
testified and were extensively crossexamined as were Mr. Cannata, Ms. Deborah
Schachter, Director of GOECS, and Mr. John Antonuk of Liberty Consulting
Group.

     As the Phase I hearings were getting under way, NU announced that it had
reached a merger agreement with the New York-based utility Consolidated
Edison (ConEd).  Under the agreement, ConEd will acquire all of the common
stock of NU for approximately $25.00 per share.  Although the merger had not
yet been formally presented to the Commission for approval, the Commission
determined during the Phase I hearings that issues related to the proposed
merger were relevant to the consideration of the Settlement Agreement.  The
Commission therefore advised the parties that, if it proceeded to Phase II,
it would receive evidence at that time concerning the effect of the proposed
merger on the Settlement Agreement.  Ph. I, Tr. Day I, p. 39 (October 18,
1999) and Order No. 23,346 (November 16, 1999).  The proposed merger has been
docketed as DE 00-009.

     At the conclusion of the Phase I hearings, the Commission issued Order
No. 23,346 (November 16, 1999) and ruled that it would move to Phase II of
the proceeding.  In that regard, the Commission concluded that the proponents
of the Settlement Agreement had presented sufficient evidence that the
Commission could conclude that the Settlement met the requirements of RSA
374-F.  The determination to proceed to Phase II was made subject to the
condition that PSNH immediately designate by November 22, 1999, its
divestiture sell and buy teams and agree that each team would conform to the
Code of Conduct proposed in the Settlement Agreement. PSNH submitted such a
designation to the Commission and indicated that it would comply with the
condition relative to the Code of Conduct.

     At the conclusion of Phase I, the Commission also made a key
determination that would be relevant to the ultimate decision on whether to
approve the Settlement Agreement.  The Commission drew the parties' attention
to the language at page 73 of the Settlement Agreement, providing that the
Commission's approval "shall endure so long as necessary to fulfill the
express objectives of this Agreement" and that such approval "is binding with
respect to matters contained herein."  Order No. 23,346 at 8.   With regard
to the so-called securitization aspects of the Settlement Agreement, which
requires the issuance of RRBs backed by an irrevocable property right in the
receivables that would be used to retire Rate Reduction Bonds, the Commission
determined that "should securitization be approved, such a limitation on
future Commissions would be appropriate within the language of the statute
creating such a property interest."  Id.  However, as to the other aspects of
the Settlement Agreement, the parties were put on notice that the Commission
would not issue an order purporting to bind future Commissions, other state
agencies or the State of New Hampshire in general.  Order No. 23,346 at 9.
Noting that the Commission is vested with express authority, upon notice and
hearing, to "alter, amend, suspend, annul, set aside or otherwise modify any
order" it issues, RSA 365:28, and that rates authorized by the Commission
"shall remain in effect until altered by a subsequent order of the
commission," RSA 365:25, the Commission concluded that only the Legislature
can divest the Commission of powers that the Legislature has specifically
conferred upon this Commission and its successors.  Order No. 23,346 at 9.

     The Commission therefore offered the proponents of the Settlement
Agreement three options: (1) remove the offending language from the
Settlement Agreement altogether; (2) accept the imposition by the Commission
of a condition that will render the language in question inoperative, should
the Settlement Agreement ultimately gain approval at the conclusion of Phase
II; or (3) seek a legislative remedy of this matter. (FN 11)  On the first
day of Phase II hearings, PSNH's counsel indicated that the Company was
willing to commit that it will not reject the Settlement if the Commission
changes the Agreement with respect to this one particular issue. Ph. II, Tr.
Day I, 139.  The other signatories to the Settlement Agreement concurred.
Id. at 140.

IV.   SUMMARY OF THE SETTLEMENT AGREEMENT

     The Settlement Agreement establishes what it refers to as Competition
Day, defined as the first day of the month in which all specified conditions
for implementing the Settlement Agreement are satisfied.  On Competition Day,
PSNH's retail customers would be permitted to choose a retail supplier of
electricity.  On or before Competition Day, PSNH would write off $225 million
after taxes, or approximately $367 million before taxes as of January 1,
2000.  The Settlement Agreement further calls for PSNH to reduce its Stranded
Costs by an additional $10 million upon the transfer of certain wholesale
contracts to affiliates.

     According to the Settlement Agreement, PSNH's rates will decline by an
average of 18.3 percent on Competition Day.  A fixed Delivery Charge of
$0.028 per kWh would apply during the first 30 months following Competition
Day, to cover retail distribution, transmission and customer service.  No
later than 29 months following Competition Day, PSNH would file a rate case,
based on the most recent four calendar quarters for which data is available
as the test year for purposes of establishing a new revenue requirement for
the delivery rate.  The new delivery rate established in that proceeding will
be applied retrospectively to the end of the initial 30-month period.  The
Settlement Agreement specifies that, in order to achieve the $0.028 per kWh
delivery charge, it will be necessary to extend the depreciation lives of
PSNH's transmission and distribution assets by ten years.

     The Settlement Agreement establishes a "non-bypassable" Stranded Cost
Recovery Charge (SCRC) with a three part settlement mechanism.  Part 1 of the
SCRC would consist of costs associated with servicing RRBs to be issued in
connection with the securitization of certain of PSNH's stranded costs.  The
assets covered by the Part 1 SCRC include: the difference between the book
value of NAEC's interest in Seabrook and $100 million, the book value of
PSNH's interest in Millstone Unit 3 as of the date the interest is
transferred to an affiliate; costs associated with the issuance of the bonds
and any premiums associated with the retirement of debt and preferred stock
up to $17 million; and a portion of the acquisition premium paid by NU to
acquire PSNH and related costs booked under FAS 109.  The Settlement
Agreement calls for the Part 1 of the SCRC to be a "discrete and segregated
charge" in order to achieve a Triple-A rating for the RRBs.

     Part 2 of the SCRC would include ongoing decommissioning expenses
associated with the Seabrook, Millstone Unit 3 and Vermont Yankee nuclear
plants.  Also included in the Part 2 SCRC would be costs associated with
PSNH's contracts with Independent Power Producers (IPPs).  Under the
Settlement Agreement, in the event the SCRC does not generate revenue
sufficient to meet both the Part 1 and Part 2 stranded costs, recovery of
Part 2 stranded costs would be deferred for future recovery with an
associated stipulated rate of return. (FN 12)  That rate utilizes a return on
equity of eight percent, PSNH's weighted average cost of debt immediately
following Competition Day, and assures a debt/equity ratio of 60/40.

     Finally, Part 3 of the SCRC would consist of non-securitized stranded
costs not otherwise included in Parts 1 or 2, offset by a return on
accumulated deferred income taxes (ADIT) associated with these costs.  Part 3
costs include any portion of the FAS 109 costs associated with the PSNH
acquisition premium that is not securitized, the value of unrecovered
obligations for retired nuclear power plants on PSNH's books as of
Competition Day, the balance on PSNH's books as of Competition Day of
deferred costs associated with IPPs, the balance on PSNH's books as of
Competition Day of deferred retail FPPAC costs, the value of PSNH's payments
to buy out its contract with Hydro Quebec, the value of its payment to buy
out PSNH's contract with Vermont Yankee, and any remaining necessary and
prudent unamortized losses associated with reacquired debt and accelerated
payoff of PSNH and/or NAEC debt, net of any such amounts in Part 1 costs.

     Under the Settlement Agreement, Part 3 stranded costs are to be credited
with the net of proceeds above or below book value from the sale of PSNH's
fossil and hydroelectric generation assets as well as NAEC's Seabrook
interest.  The Part 3 stranded costs would also be reduced by (a) $10
million, upon the transfer of PSNH's market-based wholesale power contracts
to an affiliate, (b) any net payment received by PSNH to terminate wholesale
requirements contracts other than PSNH's Amended Partial Requirements
Agreement with the New Hampshire Electric Cooperative (NHEC), and (c) the
present value of the incremental payments for the all-in costs of the RRBs if
the cost exceeds the interest rate guaranteed by PSNH. (FN 13)

     Also included in the calculation of Part 3 stranded costs are:  (a) the
revenue requirement associated with any generation assets, generation
entitlements or purchased power obligations (other than those covered in Part
2) prior to their divestiture, (b) the difference between the cost of
providing Transition Service and the revenue received for Transition Service,
(c) any positive difference between the cost of providing Default Service and
the revenue received for Default Service, and (c) a return on the accumulated
deferred income taxes associated with the securitized assets.

     Under the Settlement Agreement, the Part 3 SCRC differs from the Parts I
and II SCRCs in that Part 3 charges terminate at the earliest of two events:
(1) full amortization of non-securitized stranded costs or (2) the so-called
Recovery End Date specified in the risk-sharing provisions of the agreement.
Under the risk-sharing provisions, the Recovery End Date is pegged as
September 30, 2007 - but would be 20 days earlier for each month beyond
January 1, 2000 that Competition Day occurs.  Given the timetable in this
proceeding, the Recovery End Date would obviously be some time earlier than
September 30, 2007.

     There are numerous other risk-sharing provisions in the Settlement
Agreement.  One relates to the Settling Parties' assumption that PSNH will
realize $360 million in net proceeds from the sale of its fossil/hydro
generation assets.  Under the Settlement Agreement, the Recovery End Date
would be 30 days earlier for each $10 million by which the sale price exceeds
$360 million, or 30 days later for each $10 million by which the sale price
falls below $360 million.  Another risk-sharing provision concerns the
Settling Parties' assumption that the all-in cost of the RRBs would be 7.25
percent.  Under the Settlement Agreement, if the bonds are issued prior to
July 1, 2000 and achieve a Triple-A rating, the Recovery End Date would be 20
days earlier for each 25 basis points (0.25%) by which the all-in cost falls
below 7.25 percent.  Other similar risk-sharing provisions, calling for
possible adjustments to the Recovery End Date, involve the average weighted
cost of Transition Service, wholesale prices obtained by PSNH in connection
with its nuclear and IPP entitlements as well as its fossil/hydro generation
assets prior to their divestiture.

     Under the terms of the Settlement Agreement, the "overall average level"
of the SCRC will be $0.0379 per kWh until non-securitized stranded costs are
fully amortized or the Recovery End Date.  During the period that this
overall average level of stranded cost charge is in effect, PSNH will compare
stranded cost revenues to the amount to be recovered under Parts 1, 2 and 3.
If, pursuant to these calculations, recoverable Part 3 stranded costs exceed
the SCRC revenue, the difference would be deferred with a return for possible
future recovery under Part 3 during the ensuing six-month period.  However,
the Settlement Agreement expressly provides that in no event will Part 3
costs be deferred beyond the Recovery End Date.  In the event that
recoverable Part 3 costs are less than the SCRC revenues received, the
difference would be used to accelerate the amortization of Part 3 regulatory
assets, thereby shortening their recovery period.  At the Recovery End Date,
PSNH would write off any remaining Part 3 balances.

     Under the Agreement, PSNH would no longer have any obligation to supply
energy to its retail customers.  Instead, and as contemplated by RSA 374-F,
as of Competition Day, customers would have the option to choose a
competitive energy supplier or receive Transition Service. Transition Service
would be available for three years after Competition Day for those customers
who have not chosen a competitive supplier.  In addition, the Settlement
Agreement provides for Default Service that would function as a "safety net"
for customers who are not receiving electricity from a competitive supplier
and who are not eligible for Transition Service.  PSNH would secure
Transition Service through either a competitive bidding process or an
independent third party, at the Commission's option.  Default Service would
be acquired through a bidding process.

     The retail price of Transition Service would be $0.037 per kWh for the
first year after Competition Day, $0.038 per kWh for the next year and $0.039
per kWh for the third.  To the extent these prices vary from the weighted
average cost of the Transition Service actually provided, there would be an
adjustment to the Part 3 stranded costs and the Recovery End Date.

     Customers would also pay a System Benefits Charge (SBC), determined by
the Commission, to fund certain programs including but not necessarily
limited to the Low-Income Electric Assistance Program and energy efficiency
programs.  PSNH would provide a Low-Income Energy Assistance Program that is
consistent with the one proposed by the Commission's Low-Income Working
Group.  The Commission would decide the appropriate level of funding for any
energy efficiency programs to be paid for through rates.  Prior to
Competition Day, PSNH would spend the amounts already ordered by the
Commission for energy efficiency programs.  If, on Competition Day, the
Commission has not rendered a decision about energy efficiency programs,
charges for energy efficiency programs would be 1 mil per kWh during the
first year, 1.5 mils during the second and 2.5 mils during the third.

     The Settlement Agreement provides for freezing PSNH's FPPAC rate and
FPPAC BA amount at present levels until Competition Day.  After Competition
Day, FPPAC would be eliminated and, as already noted, the deferred FPPAC
balance would be included for recovery in Part 3 stranded costs.

     The Settling Parties agreed that the Sharing Agreement and Capacity
Transfer Agreements between PSNH and its affiliates would terminate as of
December 31, 1999, and during the hearings agreed that the only financial
compensation due any party under these agreements would involve capacity
transfer payments for November and December 1999.

     With regard to the classification of PSNH's transmission and
distribution assets, the Settlement Agreement adopts the method proposed by
PSNH in Docket No. DR 97-059.  Under this approach, the "line of demarcation"
between transmission and distribution facilities is at the "high side of
facilities that interconnect with facilities rated 69 kV and above and that
step-down to facilities rated at or below 34.5 kV."  The Settling Parties
agree that this paradigm satisfies the so-called Seven Factor classification
test adopted by FERC. (FN 14)  The Settlement Agreement allows PSNH to retain
ownership of its White Lake Combustion Turbine facility in Tamworth, to be
run on an as needed basis to maintain the reliability and stability of PSNH's
electrical delivery system.

     Customers currently served by PSNH under special contracts would have
three options if the Settlement Agreement is adopted: (1) retain the special
contract and receive Transition or Default Service with no additional
payments for energy, (2) cause the special contract to be partially unbundled
and see energy charges reduced by $0.037 per kWh, with power to be purchased
from a competitive supplier, or (3) if the Special Contract includes a
termination provision, invoke it and pay any applicable termination charges
under the terms of the contract.

     The Settlement Agreement contains detailed provisions governing PSNH's
divestiture of its power generation assets and purchased power agreements.
The auction of most fossil/hydro generation assets would commence within 30
days of Competition Day. (FN 15)  A three-round process would ensue: (1)
interested parties would be permitted to conduct limited due diligence and
make non-binding bids, (2) a group of qualified bidders would be selected and
invited to conduct detailed due diligence and submit binding bids, and (3)
possible real-time bidding among selected finalists with Commission
oversight.  At the beginning of the second round, PSNH would advise bidders
as to any "mandatory groupings" of the assets to be sold.  Municipalities
with an interest in purchasing hydro assets in their communities, and which
by then have not already reached an agreement with PSNH, will be included in
the second round if they demonstrated financial capability and if their
first-round bids are competitive with those submitted by other bidders.
Affiliates of PSNH would be expressly permitted to participate in the bidding
process, subject to an established code of conduct to assure fairness and
impartiality, and provided that any affiliate bid is equal to or greater than
the sum of the book values for all assets on which the affiliate bids. The
Settlement Agreement acknowledges that these sales require certain additional
approvals from FERC, the Securities and Exchange Commission (SEC), the
Federal Trade Commission (FTC) and the U.S. Department of Justice (pursuant
to the pre-merger notification requirements of the federal Hart-Scott-Rodino
Act) as well as regulators in Connecticut, Maine, Massachusetts and Vermont
and lenders.

     As noted above, the Settlement Agreement contemplates that
municipalities may enter into agreements with PSNH, outside the auction
process, to purchase hydroelectric assets within their borders.  PSNH would
retain the "absolute right" to reject any such municipal offer that does not
meet or exceed the price that PSNH could "reasonably anticipate" receiving
for the asset in the auction.  Further, the municipal buyer would have to
enter into a binding purchase and sale agreement within ten days of our
approving the Settlement Agreement.

     As part of the Settlement Agreement, PSNH proposes to sell at auction
its entitlement to power generated by Hydro Quebec, and the concomitant
obligation to purchase Hydro Quebec power, as well as transmission rights
associated with these entitlements.  This auction would occur separately
from, but on the same time line as, the auction of the fossil/hydro assets.

     Three parcels of land, currently owned by PSNH for possible future
development as generation sites, would also be sold under the terms of the
Settlement Agreement.  However, the method for selling these properties is
unspecified.  Under the Agreement, 50 percent of the sale price of this
realty would be credited to stranded costs with the remainder credited to
PSNH's owner.

     PSNH's interest in Millstone Unit 3, amounting to 2.8475% of the nuclear
facility, would be transferred to a PSNH affiliate at zero cost prior to
Competition Day under the Settlement Agreement.  PSNH's net book investment
in this asset would become eligible for securitization. Ratepayers would have
no claim on any net proceeds in the event the PSNH affiliate sells this
Millstone interest after its divestiture by PSNH.  Further, subsequent to the
transfer, PSNH and its ratepayers would remain obligated for its pro rata
share of site-specific decommissioning costs.

     With regard to PSNH's 4 percent interest in Vermont Yankee, the
Settlement Agreement calls for a public auction by December 31, 2000 in the
event the proposed sale of the facility has not closed by July 31, 2000.

     The Settlement Agreement contains detailed provisions relating to PSNH's
Seabrook interests and obligations.  PSNH's Seabrook-related "overmarket
obligations" to NAEC would be securitized and included in Part 1 stranded
costs.  The proceeds of this portion of the securitization process would be
used to buy down the value of the Seabrook regulatory asset on PSNH's books
to $100 million.  NAEC would be able to use the payments it receives under
these provisions to repay capital in a manner designed to reduce its costs
most efficiently.

     Further, NAEC would sell its Seabrook share via public auction by
December 31, 2003. The auction process would be subject to Commission
approval and the requirements of the Seabrook Joint Owners Agreement.  Part
of the approval process would include Commission approval of a confidential
minimum bid, and NAEC would be obligated to make reasonable efforts to
include non-NAEC ownership shares (including those of PSNH affiliate CL&P) in
the Seabrook auction in order to offer a controlling interest in the
facility.  Subject to FERC approval, NAEC's overall return on equity would be
lowered to 7 percent unless the Commission rejects a proposed Seabrook sale
or fails to act on such a proposal within 180 days of its submission.  In
that instance, and assuming the failure of any Seabrook sale proposal is not
the fault of NU or PSNH, NAEC's return on equity would be increased to 11
percent.

     A successful sale of NAEC's Seabrook interest would result in the
termination of the contract by which PSNH is obligated to purchase Seabrook
power from NAEC.  However, PSNH would remain responsible for funding NAEC's
share of Seabrook decommissioning costs. These costs would be calculated
based on full funding of decommissioning expenses by December 31, 2015.  PSNH
could enter into a new contract to fund its Seabrook decommissioning costs,
with recovery included in Part 2 stranded costs, but PSNH customers would
have no responsibility for increases in decomissioning costs beyond those
calculated based on full funding by the end of 2015.  Beginning on
Competition Day and continuing through the date on which the sale of the
Seabrook assets closes, NAEC's Seabrook power would be sold into the
wholesale power market and the proceeds credited to stranded costs.

     With regard to the fossil/hydro assets, Vermont Yankee and Seabrook, the
Settlement Agreement contains a provision relating to the possibility of a
failed auction.  PSNH would be obligated to take all reasonable steps to
avoid such a possibility.  But, if any assets remain unsold following the
auction process, the Commission would have the authority to divest the asset
or assets by a number of methods.  SA, at 51:1458-1463. Further, in the
absence of a sale, PSNH would retain the asset(s), bid the output into the
wholesale market and include the net of costs and revenues in Part 2 stranded
costs.

     PSNH would be responsible for the prudent marketing of any generation
assets, entitlements or purchase obligations that it owns or in which it
maintains an interest.  For as long as PSNH is required to purchase the
output from any IPPs under short-term avoided cost rates, it
would be deemed prudent for PSNH to sell or bid this power into the pool at
the ISO-New England market clearing price.  PSNH would auction power obtained
from IPPs under long-term contracts or long-term rate orders entered by the
Commission.

     Certain commitments PSNH has made to its employees, both those
represented by a collective bargaining agent and those who are not so
represented, are part of the proposed Settlement Agreement.  The purchaser(s)
of fossil/hydro assets would be required to assume PSNH's obligations under
the collective bargaining agreement now in place between PSNH and Local 1837
of the International Brotherhood of Electrical Workers (IBEW).  The IBEW
agreement is currently scheduled to expire on May 31, 2002.  The purchaser of
NAEC's Seabrook interest would be required to assume NAEC's obligations under
a collective bargaining agreement with Local 555 of the Utility Workers Union
of America.  Further, NAEC would "propose to require" that any buyer offer an
additional one year of continued employment to anyone who held a represented
position during the three months prior to the sale of the Seabrook assets.

     With regard to non-represented employees of PSNH and NAEC, the
purchaser(s) would be required to offer a minimum of one year of employment
at comparable wages to those received prior to the sale.  There would be a
defined severance package for any employees terminated for other reasons than
cause during the one-year period.  Further, employees terminated during the
ensuing six months would receive certain outplacement and retraining
assistance.  The purchaser(s) would also be required to provide a defined-
benefit pension plan subject to certain requirements enumerated in the
Settlement Agreement.

     The Settlement Agreement includes an agreement by PSNH to abide by the
California Affiliate Transaction Rules as interpreted by a set of rules,
appended to the Settlement Agreement, specific to PSNH and its affiliates.
PSNH would abide by these rules until the Commission enters a final order
implementing affiliate transaction rules for New Hampshire.

     The Settlement Agreement further lays out certain general principles:
PSNH agreed that it would not use its utility status to favor any affiliated
companies, that when it makes customer and/or marketing data available to an
affiliate it will make the information available to all other Competitive
Suppliers, that its generation and marketing affiliates will not share office
space or personnel, that its marketing affiliates will not use the PSNH name
or anything similar to it, that affiliate books and accounts will be open to
Commission inspection, that it will cooperate to establish relevant market-
power measurements and benchmarks that may be used to evaluate the
performance of the ISO-NE market place.  Further, the Settling Parties
recommend that marketpower disputes be resolved in a manner consistent with
the arbitration procedures enacted by Congress as part of the federal
Telecommunications Act of 1996.

     There is a provision in the Settlement Agreement relating to Exempt
Wholesale Generator (EWG) status under the Public Utility Holding Company Act
of 1935 (PUHCA) and related federal law.  Should any entity to which PSNH
sells generation assets, including any PSNH affiliate, be eligible to request
EWG status, the parties to the Settlement Agreement agreed they would support
efforts to obtain any necessary approvals and findings from the Commission.

     The Settlement Agreement characterizes securitization as "a useful tool
for lowering customers' bills and maximizing customer benefits."  The
Settling Parties have agreed to support securitization legislation permitting
PSNH to issue $725 million in RRBs, described as a "pivotal element" of the
settlement.

     The securitization portions of the Settlement Agreement call for the
Commission to issue a finance order that describes the bond transaction,
makes certain findings and includes certain orders and approvals.  The
objective of the findings to be requested is to achieve a Triple-A rating for
the RRBs when issued.

     Under the securitization provisions, PSNH would form a "bankruptcy-
remote," wholly owned, Special Purpose Securitization Entity (SPSE).  PSNH
would minimally capitalize the SPSE, allowing PSNH to treat the issuance of
the RRBs as debt for tax purposes.  PSNH would establish an
overcollateralization subaccount at a level required to achieve the desired
credit rating.

     The Settlement Agreement calls for the creation of a so-called RRB
Property, defined as an irrevocable property interest to bill and collect
non-bypassable RRB Charges in amounts that are sufficient to recover the RRB
Costs.  PSNH would sell the RRB Property to the SPSE in a transaction
intended as a "legal true sale."  The sale would include a provision that, in
the event of a PSNH bankruptcy, the SPSE would not become part of the PSNH
bankruptcy estate and PSNH's creditors would not have recourse to the RRB
Property or the RRB Charges.  The SPSE would transfer to PSNH the proceeds
from the bond sale as consideration for the RRB property. PSNH would, in
turn, be authorized to use these proceeds in a manner to be determined by the
Commission in the finance order.

     The Settlement Agreement expressly authorized the State Treasurer or her
designee to oversee the terms and conditions of the RRBs' issuance, including
tax aspects and arrangements designed to assure that PSNH acts with fiscal
prudence and the RRBs are issued at the lowest possible cost.  The SPSE would
issue the RRBs in one or more series.  To the extent allowed by the
Commission in the financing order, the form, term, interest rate (whether
fixed or variable), repayment schedule, classes, number, credit ratings and
other characteristics would be determined at the time the bonds are priced,
based on then-existing market conditions, the goal being to achieve the
lowest all-in financing cost possible.  The RRBs would be non-recourse to
PSNH and would not be secured by a pledge of the general credit, full faith
or taxing power of the State of New Hampshire.  The Settlement Agreement
contemplates that RRB charges would be billed to PSNH customers until the
expected maturity date of the RRBs, which is 12 years from their date of
issuance.  However, the Settlement Agreement further provides for these
charges to be billed for as long as 14 years if the full amortization of the
RRBs so requires.

     Securing the RRBs would be the assets of the SPSE.  Initially, PSNH
would act as servicing agent for the SPSE, responsible for calculating,
billing, collecting and remitting the RRB Charge and receive a service fee
for performing these tasks.

     The RRB Charge would be established at levels intended to provide for
full recovery of RRB costs.  It would be calculated based on the coupon rate
of the RRBs at the time of their issuance.  Had the RRBs been issued prior to
December 31, 1999, PSNH would have guaranteed all-in costs of 6.25 percent.
Should they be issued pursuant to the Settlement Agreement by July 1, 2000,
PSNH would guarantee an all-in cost of 7.25 percent.

     According to the Settlement Agreement, if the RRBs are to achieve a
Triple-A rating it is necessary to minimize bondholders' exposure to losses
due to, among other things, shortfalls in projected sales of energy, longer-
than-expected delays in bill collections and higher-than-estimated
uncollectible accounts.  Thus, the Settlement Agreement includes an elaborate
system of collection accounts associated with the RRBs as well as a true-up
mechanism.  Initially, the RRB Charge would be calculated to recover an
amount in excess of that needed to service the bonds, with the excess
diverted to a capital subaccount, an overcollateralization subaccount and a
reserve subaccount. (FN 16)  If, at a later time, income from RRB charges is
insufficient to service the bonds, the reserve subaccount would be drawn upon
first, followed by the overcollateralization subaccount and finally the
capital subaccount.  Further, the RRB charge itself would be adjusted
pursuant to a true-up mechanism.

     PSNH makes certain explicit commitments under the Settlement Agreement.
It agrees to take steps to insure that the State would receive party status
in any bankruptcy proceeding involving NU, PSNH or any PSNH affiliate as
along as any of the RRBs remain outstanding. PSNH agrees to make no dividend
payment to NU until the write-off specified in the Settlement Agreement has
been taken or the Agreement is either disapproved or fails to be implemented.
If PSNH's transmission and distribution assets are sold within five years of
Competition Day for a premium above 1.5 times the net book value of these
assets, one third of the "excess premium" would be credited to non-
securitized stranded costs.  Finally, in a provision that has become relevant
given the announcement of NU's proposed acquisition by ConEd, the Settlement
Agreement provides:

If NU itself is acquired or otherwise sold or merged [within five years of
Competition Day], it agrees that notwithstanding any contrary provision of
law, the merger, acquisition or sale shall be subject to the jurisdiction of
the PUC under RSA Chapters 369, 374, 378 or other relevant provisions, and
that the merger, acquisition or sale shall be approved only if it be shown to
be in the public interest.  A merger of NU that is subject to this section
shall not include acquisitions by NU of other entities.

     A key aspect of the Settlement Agreement is PSNH's agreement to dismiss,
with prejudice, its U.S. District Court lawsuit challenging the state's
electricity restructuring plan.  Under the Settlement Agreement, this would
occur on Competition Day.  This provision does not necessarily mean the end
of the lawsuit itself because there are other utilities involved in the case
as plaintiffs who are not signatories to the Agreement.  Further, as part of
the Settlement Agreement, the Commission would dismiss with prejudice the
following proceedings: DR 96-148 (the "Best Efforts" docket), DR 96-149 (the
"Light Loading" docket), DR 96-424 (concerning system charges to be paid by
self-generators), DR 97-014 and 98-014 (FPPAC), DR 97-059 (the PSNH Base Rate
proceeding), DE 97-167 (concerning Millstone 3), DF 97-185
(PSNH management audit), DR 98-006 and 98-071 (PSNH's Least Cost Integrated
Resource Plan) and DSF 99-066 (annual review of PSNH's bulk power projects).
(FN 17)

     As a condition precedent to implementation of the Settlement Agreement,
certain conditions must be met "to the satisfaction of all Parties."  These
conditions are: Commission approval of the Settlement Agreement without
condition or modification, unless agreed to by the Parties; approval from
PSNH's and NAEC's existing lenders; the existence of arrangements with
suppliers of Transition and Default Service; enactment of legislation
authorizing securitization; PSNH's closure on issuance of RRBs in the
principal amount of $725 million; the existence of agreements or other
arrangements for PSNH to sell any remaining power entitlements; and all
necessary approvals from FERC, the SEC, the Nuclear Regulatory Commission
(NRC) and the Connecticut Department of Public Utility Control.

     Finally, the Settlement Agreement contains certain general provisions
that bear directly on the process by which the Commission considers it.  The
Settlement Agreement provides that if it does not receive Commission approval
in its entirety, the Settling Parties shall have the opportunity to amend or
terminate it.  Acceptance of the Settlement Agreement by the Commission
"shall not be deemed to restrain the PUC's exercise of its authority to
promulgate future orders, regulations or rules which resolve similar matters
affecting other parties in a different fashion."  SA, at 73:2085-2087.
Commission approval of the Settlement Agreement would have to endure so long
as necessary in order to fulfill the objectives of the Agreement.
The Settlement Agreement expressly does not resolve any jurisdictional issues
that might arise between the Commission and FERC.  In addition, the
Settlement Agreement contains this language:

The approvals contemplated by this Agreement shall not be construed as
requiring the PUC to relinquish its authority to develop new policies and
issue orders or to the initiate [sic] investigations when it deems such
actions are in the public good, except that approval of this Agreement shall
be binding with respect to the matters contained herein, including the
Stranded Cost, write-off and securitization provisions subject only to PUC
reconciliation and accounting as provided in the Stranded Cost Recovery
Charge section of this Agreement.  SA, at 73:2092-2097.

As noted, supra, the Commission placed the parties on notice at the
conclusion of Phase I that the Commission would not approve the Settlement
Agreement to the extent these provisions purport to bind future Commissions.

V.   POSITIONS OF THE NON-SETTLING PARTIES AND NON-SETTLING STAFF-Generally

A.   Representative Jeb Bradley

     Representative Jeb Bradley serves as co-chair of the Electric Utility
Restructuring Legislative Oversight Committee. (FN 18)  He identifies four
areas in which he believes the Settlement Agreement requires modification:
(1) the need for additional burden-sharing by PSNH with regard to stranded
costs, (2) additional assumption by PSNH of the risk of unforeseen economic
and/or technological changes, (3) further reward-sharing by PSNH of the
benefits of
securitization, and (4) efforts to develop a competitive marketplace for
electricity at retail in New Hampshire.

     Representative Bradley concludes with a list of nine possible areas in
which the Settlement Agreement could be made more ratepayer-favorable,
stressing that their overall effect is more important than which particular
ones are adopted.  These suggestions are (1) reduction of the delivery
service charge with an understanding that PSNH or the Commission could file a
new rate case at any time, (2) reduction of the delivery service charge upon
consummation of the proposed NU/Consolidated Edison merger, (3) lowering the
interest rate on accumulated deferred income taxes, (4) tying any increase in
the Seabrook-related return on equity to the sale of Seabrook, (5) reducing
the amortization period for the fossil/hydro assets from 12 to 7 years, (6)
setting the delivery service charge for special contract customers to the
same level charged regular customers, (7) preventing PSNH from recovering
from its customers any costs associated with its settlement with NHEC, (8)
reducing stranded costs through further IPP buy-downs, and (9) increasing the
proposed $367 million pre-tax write off.

B.   Representative Gary Gilmore

     Representative Gary Gilmore of Dover is a member of the Electric Utility
Restructuring Legislative Oversight Committee.  Representative Gilmore states
that the Settlement Agreement, as submitted to the Commission, is not viewed
favorably and he urges the Commission to improve the Settlement for
ratepayers.  With respect to the generation asset sales, he cites the
following concerns:  (1) the sales of PSNH's generation assets should be
administered by the Commission to assure that bidders receive comparable and
fair treatment and that the assets are sold at the highest possible price;
(2) all asset proceeds should be rapidly amortized; and (3) hydroelectric
assets sales should be structured to allow meaningful municipal participation
without reducing the sale price of the assets.

     Representative Gilmore also urges the Commission take every effort to
retain the proposed average rate reduction of 18 percent to 20 percent in the
first year, while eliminating known or reasonably expected deferrals.  He
believes the reclassification of transmission and distribution assets should
be treated in a separate docket and asks the Commission not to rule on it at
this time.  Finally, Representative Gilmore believes that the synergy savings
of the NU/ConEd merger must be shared with ratepayers, as should some portion
of the premium paid to NU shareholders.

C.   THINK - New Hampshire

     Mr. Jim Rubens, President of THINK - New Hampshire a non-profit issues -
advocacy group with statewide membership, urges the Commission to reject the
Settlement.  In fact, THINK - New Hampshire asserts that the Commission is
forbidden by law from approving the Settlement because there is a significant
possibility that it permits greater stranded cost recovery than would be
allowed in a regulated environment and because there are no sustainable
claims that the Settlement will allow a range of viable competitive
suppliers.  Should the Commission approve the Settlement, THINK - New
Hampshire requests that the Commission: (1) increase the Transition Service
rates to at least $0.045 per kWh; (2) cap the stranded cost charges at
amounts not to exceed those projected by the Settling Parties; and (3) if the
Settlement is approved without conclusive evidence that it is more favorable
than the rate case, reduce the stranded cost recovery so that the probability
becomes low that a rate case would yield better results.

D.   Business and Industry Association of New Hampshire

     The Business and Industry Association (BIA) is a group representing
approximately 450 New Hampshire businesses.  It urges the Commission to
approve the Settlement Agreement, with certain modifications.  The BIA
proposes the following modifications: (1) ensure that the proposed rate
reductions on the non-commodity rate components are maintained over time, and
that SCRC rate design risk is mitigated to prevent large swings in revenue
requirements among customer classes; (2) set Transition Service charges at
market rates to avoid deferrals; (3) link the auctions of generation assets
with the Transition Service offering; (4) hire an independent auctioneer,
especially if a PSNH affiliate plans to participate in the auctions; (5)
modify the SCRC protocol such that RED is "left in place" and use any
adjustment that would cause RED to move forward to reduce the SCRC instead;
(6) amortize the proceeds from the fossil/hydro auctions over seven years,
not twelve; (7) apply the Stipulated Rate of Return to any credits to the
revenue requirements; and (8) defer the proposed new fees for 30 months or
modify the Settlement to incorporate the new revenues into the financial
model and modify the rates accordingly.

E.   Cabletron Systems, Inc.

     Cabletron Systems, Inc. is an information technology company based in
Rochester, New Hampshire.  Among the issues it raises is a procedural one,
relating to the timing of the Commission's final order in this docket.
Specifically, Cabletron's concern relates to approval of the Settlement
Agreement with conditions, triggering a right by the Settling Parties to
withdraw the Settlement from further consideration.  Cabletron believes it
would be at a procedural disadvantage as a non-settling party because it
believes its 30-day period to seek reconsideration would coincide with the
period in which the Settling Parties would be deciding on possible withdrawal
of the agreement.  In Cabletron's view, there is a substantial possibility
that nonsettling parties could end up expending significant resources on a
rehearing request that ultimately becomes moot.  This, according to
Cabletron, raises due process concerns.  Accordingly, Cabletron asks the
Commission to suspend the effective date of this order for ten days and give
the Settling Parties the same period to indicate whether they intend to
withdraw the Settlement Agreement.

     Cabletron generally concurs with the policy comments and analysis in the
post-hearing brief filed by Representative Jeb Bradley, except that Cabletron
takes no position with respect to Representative Bradley's comments regarding
the additional savings associated with IPP buydowns.  Cabletron urges the
Commission to make a finding that Transition Service deferrals are not in the
public interest and to condition the Settlement to clearly prohibit the
authorization of any such deferral account.  In the alternative, the
Commission should condition the Settlement Agreement such that customers who
do not contribute to the creation of the Transition Service deferral account
be exempt from the requirement to pay for it.  Finally, Cabletron asks the
Commission to modify the nuclear sales component of the Settlement such that
the issue of how and when the NAEC obligation is to be sold is determined in
a separate docket in which the Commission will not be restricted in the
criteria it may use to establish a minimum bid.

F.   Great Bay Power Company

     Great Bay Power Company (Great Bay) owns a 12 percent interest in the
Seabrook nuclear power plant.  It is the corporate successor to EUA Power
Corporation that sought bankruptcy protection in 1991 and was subsequently
reorganized under new ownership.  Great Bay is an Exempt Wholesale Generator
within the meaning of the federal Public Utilities Holding Company Act and
has no retail customers.

     Great Bay urges the Commission to reject the Settlement Agreement
outright.  If however, the Commission determines to conditionally approve the
Settlement, Great Bay asks that the Commission, at a minimum, require the
following changes to the agreement: (1) prohibit PSNH from recovering the
cost of capital additions to generating plant that have been incurred since
the date of the Restructuring Act, or require PSNH to submit evidence
sufficient to prove that such additions mitigated the Company's stranded
costs;  (2) require PSNH to provide Transition Service on a basis that will
not create deferrals;  (3) require PSNH to submit its sales of power during
the period prior to asset divestiture to a full, traditional prudence review
by the Commission, rather than establishing an arbitrary prudence standard in
advance;  (4) reject the $0.028 per kWh delivery rate proposed by PSNH and
establish a lower delivery rate that is based on PSNH's actual cost of
service, using the capital structure that will be in place during the period
that the delivery rate is in effect;  (5) require PSNH to implement cost
based rates;  (6) set the rate of return on Part 3 stranded costs based on a
cost of equity that can be adjusted periodically, as proposed by Mr.
Kosnaski, rather than fixing the ROE, as proposed by PSNH;  (7) require PSNH
to proceed immediately to take all steps necessary to unbundle its
transmission and distribution rates;  (8) not permit PSNH to seek recovery of
increased costs resulting from regulatory orders and accounting changes
during the IDCP if the Company is otherwise earning a reasonable rate of
return;  (9) not base the delivery charge in this case on an assumption that
lost revenues from special contracts should be recovered from other
ratepayers.  Instead, the Commission should either lower the delivery charge
accordingly or require PSNH to submit evidence sufficient to find that
collecting such costs from non-special contract customers is in the public
good;  (10) require PSNH to clarify the record with regard to whether it
agrees that, if the Settlement is approved, the Commission will continue to
have the authority to make rate design changes with regard to the various
components of the SCRC;  (11) authorize an addition to the proposed SBC to
provide decommissioning funding assurance with regard to Great Bay's share of
Seabrook decommissioning expense;  (12) require that any excess funding of
decommissioning expense be returned to ratepayers;  (13) require the Settling
Parties to provide a structure under which the Commission can exercise
jurisdiction over PSNH's affiliates in the event it needs to in accordance
with the terms of the Settlement Agreement; and  (14) continue to
require that the Settlement Agreement will be subject to the continuing
jurisdiction of the Commission and other applicable statutory authority.

G.   PJA Energy Systems Design

     Through its principal, Mr. Pentti J. Aalto, PJA Energy Systems Design
urges the Commission to reject the Settlement Agreement in its present form
and to direct all parties in the docket to conduct further open negotiations.
In Mr. Aalto's view, the process of arriving at the Settlement Agreement was
flawed because it did not allow for input from a sufficient number of
interested parties.  Mr. Aalto describes the Settlement Agreement as a
"secret deal" in which "[t]he actual interests of the settling parties are
not clearly defined and are therefore not subject to public scrutiny and
judgment."  PJA Energy Systems Brief at 8.

H.   Office of Consumer Advocate

     The Office of Consumer Advocate (OCA) does not urge the Commission to
reject the Settlement Agreement outright, but instead proposes a series of
modifications that it views as necessary to protect the public interest.  The
OCA requests that the Commission require the following modifications to the
Settlement Agreement: (1) bid Transition Service out by class and make
necessary adjustments to the SCRC such that each class receives the same
percentage rate reduction; (2) consider a one year program of subsidized
retail adders as a system benefits charge at the end of the third year of
Transition Service if competition at the retail level fails to materialize;
(3) permanently assign the total stranded costs proportionately by class; (4)
delay the phase-out of the "humped" residential rate design; (5) deny PSNH's
proposal regarding Field Collections and open a separate generic docket to
address them; (6) only allow the imposition of a late payment fee for
residential customers after an educational period and if the corresponding
revenues are recognized in PSNH's revenue requirement; (7) complete the rate
case and all the other outstanding dockets; (8) accept Mr. Long's proposal
that no NU affiliate would participate in the generation  asset auctions; (9)
exclude any ConEd affiliates from participating in the generation asset
auctions; (10) provide the State with the right of first refusal to match the
winning, or, if appropriate, minimum bid for the Seabrook interest; (11)
match the Energy Efficiency revenues received from a class and the
expenses/service provided that class; (12) cap the ratepayer liability or
recovery mechanism as developed in the Settlement Agreement at the same
amount as the Environmental Remediation Reserve; (13) find that NU's actions
regarding its commitment to perform "best efforts" renegotiations breached
the Rate Agreement; (14) find that NU's failure to protect the Sharing
Agreement violated its contractual obligations and adjustments totaling $60
million annually should be imputed to those rates; (15) treat Special
Contracts in the manner discussed in the Commission's Final Plan (DR 96-150,
February 28, 1997); and (16) condition the NU/ConEd merger in the following
four ways: (a) reduce the initial average stranded cost rate per kWh by the
same percentage of stranded benefits for which ratepayers are responsible;
(b) modify the list of reasons why the $0.028 per kWh average delivery charge
over the IDCP can change to include savings arising from a merger during the
IDCP; (c) state that the door, which NU said is closed on October 18, 1999,
is closed and locked with regard to the absolute inability of PSNH/NU/ConEd
to recover any of the acquisition premium from ratepayers; and (d) limit the
amount of the merged corporations acquisition of generation assets to the
very limited role Mr. Morris testified to on Ph. I, Tr. Day VII, pages 62-65.

I.   New England Power Co. & Granite State Electric Co.

     New England Power Company (NEP) is a minority owner of the Seabrook
nuclear power plant.  Its affiliate, Granite State Electric Company (GSEC) is
a transmission and distribution utility serving customers in New Hampshire.
The two affiliates appear jointly to address issues relating to Seabrook
divestiture.  NEP and GSEC request that the Commission approve Section VIII
(K) of the Settlement Agreement and take all actions necessary in its
consideration and approval of the Definitive Plan to Sell Seabrook to assure
that the highest possible value is received for the asset including: (1)
require that NAEC unbundle its Seabrook entitlement with those of other
interested Joint Owners; (2) reject a minimum bid price if it determines that
the use of a confidential minimum bid price would hamper participation in the
auction and diminish value; and (3) provide that the December 3, 2003 sale
date is a deadline, not a target, and require that NAEC take all actions
necessary to expedite the auction process.

J.   City of Manchester

     The City of Manchester urges the Commission to reject the Settlement
Agreement outright and simply "return to the restructuring process
contemplated in RSA 374-F."  City of Manchester Brief at 2.  Specifically,
the City believes the Commission should complete the PSNH Interim Stranded
Cost proceeding, issue a final order in that docket and, thereafter, seek
relief from the U.S. District Court injunction prohibiting the Commission
from implementing retail competition in PSNH's service territory.  According
to the City, the divestiture of the generation assets of NU affiliates in
Connecticut and Massachusetts demonstrates that NU can no longer claim
irreparable harm if New Hampshire also moves forward to such divestiture.
Further, according to the City, the Commission can and should implement
securitization in the context of PSNH compliance filings made pursuant to an
Interim Stranded Cost order.

     If, however, the Commission decides to use the proposed Settlement
Agreement as a basis to restructure PSNH, then the City of Manchester urges
the Commission to impose the following conditions: (1) reduce the stranded
costs claimed under the Settlement by $373 million, make necessary
adjustments to the SCRC and require that the SCRC be reconciled annually; (2)
require that Transition Service be competitively bid and priced at market
rates to avoid deferrals; (3) reduce the delivery charge to $0.026 per kWh or
less and provide for a "re-opener" of the delivery charge in order to pass
through any merger related savings that are likely to occur during the IDCP;
(4) reduce the proposed "gross of tax" level of securitization of $725
million to a "net of tax" level of securitization of $438 million, or in the
alternative, use the regulated average cost of capital for the ADIT; (5) the
Commission should have oversight authority regarding any dispute as to the
purchase price to be paid by a municipality desiring to purchase
hydroelectric facilities within their boundaries prior to the time of PSNH's
divestiture of those facilities; and (6) condition approval of the Settlement
Agreement upon ConEd, or any other acquiring company, not seeking recovery of
any portion of any acquisition premium paid, or recovery of any portion of
acquisition premium paid on the basis of offsetting merger savings. Also, the
City recommends that the Commission keep the Settlement Agreement docket open
until the merger docket is completed, at which time the Commission should
make its final determination as to the appropriate level of stranded cost
recovery.

K.   Seacoast Anti-Pollution League

     The Seacoast Anti-Pollution League (SAPL) is a 350 member citizen
environmental protection group.  SAPL intervened to ask the Commission to
strengthen nuclear safety and air emissions provisions of the agreement.

L.   Conservation Law Foundation

     The Conservation Law Foundation (CLF) addresses two issues:
environmental improvement and energy efficiency.  Both are policy objectives
of the restructuring statute, according to CLF, referencing RSA 374-F:3, VIII
and X.  CLF urges the Commission not to approve the Settlement unless and
until it includes provisions requiring PSNH's fossil plants to reduce NOx
emissions and SO2.  CLF also urges the Commission to approve the funding
levels for energy efficiency programs at the levels set forth in the
Settlement.

M.   Save Our Homes Organization/Community Action Programs

     The Save Our Homes Organization (SOHO), a low, moderate and fixed income
tenants organization in Portsmouth, New Hampshire, and the state's Community
Action Programs (CAP) jointly recommend approval of the Settlement Agreement,
subject to certain conditions. SOHO/CAP explicitly indicate their support of
the provisions of the Settlement Agreement
concerning energy efficiency programs, default service and the Energy
Assistance Program.  They ask that the Commission condition approval of the
Settlement on retention of the residential "humped" rate design during the 30
month IDCP.

     SOHO/CAP urge the Commission to reject the elements of PSNH's rate
design proposal that eliminate the elderly customer discount and introduce
new service charges for residential customer Late Payments and new Field
Collection charges and raises the connect and reconnect fees.

N.   Campaign for Ratepayers' Rights

     CRR urges the Commission to reject the Settlement Agreement unless a
number of conditions are imposed to significantly improve the Agreement.  CRR
believes the minimum conditions required for approval include: (1) eliminate
the Transition Service deferral without eliminating the advertised rate
reductions; (2) limit the securitization to no more than $500 million; (3)
establish a "claw back" mechanism to provide a vehicle for ratepayer sharing
in the gain from the ConEd merger; (4) ensure that the Seabrook rate of
return not be increased above 7 percent; (5) impose a bidder requirement for
environmental improvement to new source performance standards in the auction
of fossil assets; (6) preclude PSNH, NU and ConEd from re-entering the
generation market by bidding on the generating assets; and (7) address the
concerns of the municipalities by providing them a reasonable opportunity to
acquire the hydroelectric facilities.

O.   Freedom Partners, L.L.C.

     Freedom Partners, L.L.C. (Freedom Partners) recommended that the
Commission approve the proposed Settlement with such conditions as are found
to be in the public interest.  Freedom focused its comments on Transition
Service and rates and T&D service and rates, recommending that the Commission
set Transition prices at market levels and that it require PSNH to unbundle
T&D rates.  Freedom also recommended that the Commission do a full and
complete review of the circumstances surrounding the Rate Agreement to
determine the nature and scope of any contractual obligation.  In addition,
Freedom recommended that the Commission benchmark the federal litigation and
the rate case.

P.   New Hampshire Consumers Utility Cooperative

     The New Hampshire Consumers Utility Cooperative (NHCUC), a non-profit
energy aggregator, seeks modification of the provisions of the Settlement
Agreement relating to Transition Service.  According to NHCUC, the Transition
Service provisions as drafted will not lead to meaningful retail competition.
NHCUC offers an alternative plan to provide incentives and subsidies to
foster development of cooperative, non-profit and municipal energy
aggregations.

Q.   Staff Advocates

     The Staff Advocates submitted testimony of three witnesses, Messrs.
George McCluskey, Douglas Smith and Richard LaCapra.  Mr. Smith provided a
projection of wholesale energy market prices for the years 2000 through 2007
as an alternative to the projection of the Settling Parties.  Applying Mr.
Smith's projection, Mr. McCluskey recommended significant modifications to
the proposed Settlement Agreement related to stranded cost recovery.  In the
view of the Staff Advocates, the Commission cannot simply endorse the
Settlement Agreement on the theory that it is a reasonably negotiated
compromise on disputed issues.  Rather, according to the Staff Advocates, the
Commission must determine that each provision of the Settlement Agreement
relating to stranded costs meets the requirement that such charges be
equitable, appropriate, and balanced" is in the public interest, and
"substantially consistent" with the Restructuring Act's inderdependent policy
principles pursuant to RSA 374-F:4, V.

     Staff Advocates urge the Commission to modify the Settlement Agreement
in the following ways: (1) specify that customers be credited with a return
on ADIT associated with the securitized assets calculated using the Company's
weighted average cost of capital; (2) permit the Commission to establish a
minimum bid for NAEC's Seabrook using an administrative valuation of
Seabrook; (3) allow 50 percent recovery of PSNH's unrecovered contractual
obligation in the Maine and Connecticut Yankee plants; (4) reflect a $78
million reduction in Part 3 Stranded Costs associated with the generation-
related regulatory liabilities identified by Staff Advocates; (5) exclude
from stranded cost recovery the Hydro Quebec transmission Support Agreement
payments, or at a minimum, mitigate the proposed $62 million recovery by the
value the Company receives from the facilities; (6) exclude from the final
FPPAC Deferral Balance: (a) the $7 million associated with the January 1998
outage of Seabrook Station; and (b) $18.75 million, one-half the amount
associated with the Seabrook Unit 2 spare parts sale; (7) require the
Settling Parties to recalculate the SCRC based on corrected data for loss on
reacquired debt and exclude the non-generation-related portion of the loss on
reacquired debt; (8) reduce the Part 3 Stranded Costs by $2 million to avoid
double recovery of Millstone 3 nuclear fuel and M&S inventory costs; (9)
correct for certain Part 3 Stranded Costs not properly reflected in the model
of the Settling Parties; (10) use a 6.70 percent return on equity in the
return applied to the balance of the Part 3 Stranded Costs; (11) adopt an
annual reconciliation approach instead of a risk-sharing/deferral approach;
and (12) find that it is appropriate to take into account the acquisition
premium received by NU shareholders when making a final determination of
stranded cost recovery and determine a formula or establish principles that
would govern the manner in which the acquisition premium would be taken into
account in determining final stranded costs.

VI.   POSITIONS OF NON-SETTLING PARTIES BY ISSUE

A.   BENCHMARKING

1.   Parties other than Staff

     On the subject of benchmarking, Freedom Partners contends that the
record in docket DR 89-244, which led to the Commission's approval of the
Rate Agreement, demonstrates that NU committed itself as PSNH's new owner to
returning to traditional ratemaking at the conclusion of the seven-year fixed
rate period with no "qualifications, conditions, constraints, limitations or
exceptions."  Freedom Partners Brief at 7.  In support of that proposition,
Freedom Partners cites the testimony of various NU executives in that docket.
Further, with regard to the likely outcome of a contested PSNH rate case,
Freedom Partners points out that the Commission is not required to use any
particular ratemaking methodology.  According to Freedom Partners, the fixed
rates contained in the Rate Agreement were established using a market-based,
rather than a cost-based, methodology that assumed revenues would actually
decline if rates were set any higher than they were.  Freedom Partners
further contends that in a contested rate case PSNH would have the burden of
demonstrating (1) the prudence of its expenses and investments, (2) the
extent to which its investments are used and useful and (3) the affordability
of the resulting rates, which Freedom Partners equates with the concept that
utilities' rates must be non-exploitative. According to Freedom Partners, the
appropriate measure of whether rates are exploitative is the rates that other
similarly situated customers pay for comparable service.  In Freedom
Partners' view, the rate path approved in connection with the Rate Agreement,
while reasonable at the time, has become exploitative.

     Representative Bradley acquaints the Commission with a measure pending
in the Legislature that would require the Commission to conduct a traditional
PSNH rate case prior to any legislative approval of the Settlement Agreement.
He deems it critical that the Commission compare the Settlement Agreement to
the likely outcomes of a rate case.  In particular, Representative Bradley
asks the Commission to determine the expected rate path under the Settlement
Agreement and compare it to the path of expected retail rates under
traditional ratemaking.

     It is also Representatives Bradley's view that the write-off PSNH
proposes to take under the Settlement Agreement is not as valuable as
previously thought in light of an accounting error discussed in the testimony
of Messrs. Naylor, Cannata and Antonuk.  Bradley Brief at 11. Representative
Bradley indicates that Mr. Naylor testified on behalf of Non-Settling Staff
that PSNH made an incorrect adjustment to the FAS 109 treatment of the PSNH
acquisition premium. Id.  Messrs. Naylor and Cannata testified on rebuttal
that correction of this error represents an additional decrease of 2.6
percent in PSNH's rates for benchmarking purposes.  This, according to
Representative Bradley, provides additional support for his view that PSNH is
not shouldering its fair share of the restructuring burden.

     With regard to benchmarking, Mr. Rubens takes the position that there is
at least a "serious possibility" that traditional ratemaking would be more
favorable to ratepayers than the Settlement Agreement by "tens of millions"
of dollars.  In Mr. Rubens' view, the Restructuring Act compels the
Commission to litigate the stayed rate proceedings fully in order to
eliminate the uncertainty.

     With regard to benchmarking, it is OCA's position that a full rate case
would yield a reduction in PSNH rates of between 11 and 16 percent, without
even considering the adjustments made by the Commission's Non-Settling Staff.
Further, even taking the Settling Parties' contentions into account, OCA
believes PSNH ratepayers would be entitled to a temporary rate refund of at
least $300 million, and that no one contested its assertion that the
elimination of Seabrook deferrals in early 2001 would yield an automatic rate
reduction of $113 million a year or 14.8 percent.  Ph. II, Ex. 58.

     According to OCA, its witness, Mr. Kenneth Traum, considered certain
rate-related issues not raised by Non-Settling Staff, e.g., discounts on
Special Contracts, reduced return on Acquisition Premium, and disallowance of
Millstone 3 costs and return related to imprudent outages at that facility.
In OCA's view, Mr. Traum's testimony supports an additional $100 million of
reduced annual revenue beyond that identified by Non-Settling Staff Brief at
page 18. It is also OCA's view that, once the pending dockets are resolved,
securitizing $506 million in assets related to NAEC would further reduce
rates by an additional 3.5 percent.

     OCA disputes certain adjustments PSNH would make to Mr. Naylor's
benchmarking efforts, as reflected in Phase II, Ex. 201.  PSNH would reduce
Mr. Naylor's 10.07 percent rate reduction by 1.62 percent to reflect a
"systems benefits adjustment."  OCA believes PSNH omitted several offsets in
this regard, specifically demand-side management, existing discounts and an
adjustment to uncollectible expenses to reflect reduced rates and the
existence of the lowincome assistance program.  PSNH would reduce Mr.
Naylor's figure by 0.86 percent to cover incremental costs associated with
weather normalization.  OCA adds that it agrees with Mr. Naylor that the
impact of weather on sales should be recognized; OCA disputes PSNH's belief
that Mr. Naylor's figure must be adjusted by 3.72 percent to cover "other
cost increases." According to OCA, PSNH has failed to align the applicable
time periods when calculating the relevant revenues, expenses and
investments.  OCA further contends that, by virtue of a mathematical error,
this figure should really be 1.23 percent.

     OCA urges the Commission to determine that NU and PSNH have failed to
meet their commitment in the Rate Agreement to undertake their best efforts
to renegotiate PSNH's contracts with 13 small power producers.  According to
OCA, the record here establishes that as early as February 28, 1990, NU
failed to follow up on requests for proposals to renegotiate these contracts,
failing to act until 1993 when its renegotiations yielded a 44 percent
savings, based on net present value, in costs associated with two of these
contracts.  According to OCA, renegotiation of the remaining contracts
eventually yielded a net present value savings of roughly 20 percent, which
would have been doubled had NU exercised the requisite best efforts.

     On the subject of spare parts related to the Seabrook Unit II, OCA
accuses PSNH of deliberately seeking to obscure the fact that PSNH's $700
million interest in Seabrook includes the Unit II parts and is thus already
being charged to ratepayers.  OCA cites Exhibit 83 in docket DR 97-014 as
clarifying this issue in favor of OCA's position.  OCA recommends that the
Commission require that when Seabrook is auctioned, that PSNH auction
Seabrook as is and also as if it would have four steam generators for
replacement available.  The difference would be a reduction in PSNH's
stranded costs due to NU selling Unit II spare parts without compensating
ratepayers.

     OCA's penultimate point regarding benchmarking is that the Commission
should impute benefits of approximately $60 million per year to account for
PSNH's failure to pursue remedies under the Rate Agreement in connection with
the Sharing and Capacity Transfer Agreements becoming inoperable on January
1, 2000 due to termination of CL&P's load obligations as a result of
Connecticut's restructuring legislation.  OCA points out that PSNH took no
action in this regard despite having filed suit in federal court against this
Commission to press its allegations that restructuring in New Hampshire would
lead to a breach of the Rate Agreement.

     OCA asks the Commission to determine as part of its benchmarking process
that the Rate Agreement is not a binding contract and that, accordingly,
efforts to vindicate any contractual rights under the Rate Agreement would
fail.  The OCA essentially contends that the Rate Agreement simply outlines a
set of commitments made to the Bankruptcy Court by the Signatories, thus
facilitating PSNH's emergence from bankruptcy in its new form as an NU
subsidiary.  OCA bases its position on the testimony of Attorney Harold T.
Judd who, at the time the Rate Agreement was negotiated, served as a Senior
Assistant Attorney General.  Mr. Judd participated directly in these
negotiations and was responsible for drafting RSA 362-C. According to Mr.
Judd, it was of paramount importance to the State that the authority of the
Commission to set rates not be compromised by the terms of the Rate
Agreement.  Mr. Judd further testified that prior to his joining the Office
of the Attorney General, that office had conducted a thorough inquiry
regarding the contractual nature of the Rate Agreement and had concluded that
the State could bind itself in contract only by expressly stating so.  It was
Mr. Judd's testimony that the State in its negotiations consistently refused
entreaties to bind itself in contract in order to facilitate PSNH's emergence
from bankruptcy.  According to OCA, Mr. Judd's testimony to that effect is
unrebutted.

     OCA also grounds its analysis in the New Hampshire Supreme Court's
decision in Appeal of Richards, 134 N.H. 148 (1991).  In Richards, the Court
determined that the Commission's approval of the PSNH rate plan embodied in
the Rate Agreement met the requirement in RSA 362-C:3 for rates that are
"just and reasonable."  Id. at 164.  According to OCA, the fact that such an
analysis, rather than a discussion of contract principles, was determinative
in Richards demonstrates that the Rate Agreement is non-contractual.

     According to OCA, assuming arguendo that the Rate Agreement is and
remains contractually binding, based on the Rate Agreement's provisions
permitting PSNH to receive a return on the unamortized portion of NU's
acquisition premium, only a 1 percent return is appropriate.  OCA contends
that the unamortized acquisition premium should be deemed not "used and
useful" because it requires rates to be so high that they are unaffordable
and inconsistent with regional average rates, the latter being a rate level
OCA contends NU committed itself to achieving by the terms of the Rate
Agreement.  In OCA's view, this reduced rate of return reflects NU's failure
to meet its commitments under the Rate Agreement.

     OCA further alludes to the language in the Rate Agreement providing for
a seven-year fixed rate period.  According to the OCA, at the end of those
seven years the Commission was free to return to traditional ratemaking with
regard to PSNH.  It is OCA's contention that, assuming the existence of a
contract arguendo, the Commission is simply obligated to set
PSNH's rates at a level that is reasonable and affordable.  OCA's final
assertion on the issue is that the non-investment grade bond ratings attained
by PSNH in the wake of the Rate Agreement demonstrate that investors did not
view PSNH as having entered into a contract that would guarantee the
investors recovery of their investment.

2.  Staff Advocates And Non-settling Staff

     In addition to considering whether claimed stranded costs could be
recoverable under normal ratemaking, the Staff Advocates address two
benchmarking issues.  First, they contend that PSNH's proposed after-tax
write-off of $225 million is understated because PSNH would face significant
disallowances in a traditional rate case because certain of its assets would
be deemed not used and useful.  Second, they contend that PSNH's benchmarking
analysis improperly excludes certain significant benefits that would accrue
to ratepayers through the Sharing Agreement.

     With regard to the "used and useful" issue, the Staff Advocates invoke
Appeal of Conservation Law Foundation, 127 N.H. 606 (1986), in which the New
Hampshire Supreme Court distinguished between the "used and useful"
requirement and the separate requirement that expenses be prudently incurred.
According to the Staff Advocates, the "used and useful" issue arises because
PSNH will have excess capacity of 384 MW in 2000 and 275 MW in 2005, not
including the loss of the load associated with NHEC.  The Staff Advocates
concede that a "used and useful" disallowance is not warranted as soon as an
electric utility's capacity exceeds its margin requirement, but, rather,
contend that such action becomes appropriate "when the excess .
 . . becomes substantial and continues over time."  Staff Advocates Brief at
45.  With regard to the argument that such disallowances would require PSNH
to receive a higher return on equity to account for the increased risk, the
Staff Advocates' view is that PSNH's cost of equity already reflects this
risk.

     Secondly, the Staff Advocates contend that any benchmarking analysis
conducted by the Commission should take into account benefits of between $60
million and $76 million per year that would accrue in the absence of
restructuring as a result of the Sharing Agreement and the Capacity Transfer
Agreements.  The Staff Advocates note that this revenue has been lost to PSNH
as a result of industry restructuring in Connecticut and Massachusetts.
However, their position is that NU should have brought to the attention of
the regulatory agencies in those states that their restructuring plans would
result in harm to PSNH ratepayers by terminating capacity transfer revenue
and joint dispatch savings revenue to PSNH from its affiliates.  According to
Staff Advocates, this lost revenue would be imputed to PSNH in a traditional
rate case.

     Next the Staff Advocates recommend modification of the Settlement
Agreement to foreclose recovery on the $7 million associated with the January
1998 unplanned outage at Seabrook and an additional $18.5 million,
representing half the sum associated with the sale of Seabrook spare parts.
The Staff Advocates rely on the benchmarking testimony of Mr. Cannata of the
Settling Staff, who (1) predicted a high likelihood that the Commission would
conclude in a fully litigated case that the 1998 Seabrook outage was the
result of imprudence and (2) similarly predicted that the Commission could
determine that accounting practices should be revised to reflect that the
Seabrook Unit II parts revenue should accrue to ratepayers.

     Non-settling Staff's pre-filed testimony includes extensive analysis of
updated rate-case data filed by PSNH in January 1999, based on a September
30, 1998 test year.  However, at the hearing, Mr. Naylor testified that this
analysis is not intended as a substitute for a full rate case and is provided
solely for benchmarking purposes, i.e., to allow the Commission to pinpoint a
range of possible outcomes in the rate-case docket and then to compare those
outcomes to the results proposed by the Settlement Agreement.

     Mr.  Naylor notes that PSNH made its original base rate case filing in
May 1997 based on a 1996 test year, and that the Company revised its filing
in January 1999 based on a test year ending on September 30, 1998.  Mr.
Naylor further reports that much of the discovery, and three weeks of on-site
field work, had been completed as of early June, when the Memorandum of
Understanding preceding the Settlement Agreement was filed with the
Commission.

     According to Mr. Naylor, if this rate case were presented to the
Commission for adjudication, Staff would recommend a 10.07 percent reduction
in PSNH's revenue requirement. This figure is in addition to the 6.87 percent
reduction the Commission had approved in its temporary rate order of November
6, 1997 (Order No. 22,784) and effective with bills rendered as of December
1, 1997 - applicable retroactively to July 1, 1997.

     Mr. Naylor's analysis is based on an 11.34 percent cost of equity as
recommended by Mr. Kosnaski, and a rate base significantly less than that
proposed by PSNH.  Included in the schedules appended to Mr. Naylor's
testimony are Staff's proforma adjustments to PSNH's rate base to account for
the declining balances in PSNH's regulatory assets for a period of 12 months
after the end of the test year.  This results in a rate base reduction of
$64.778 million.  Mr. Naylor invokes the determination in the 1997 temporary
rate order that the amortization of regulatory assets is an "extraordinary
circumstance not only justifying but requiring a modification" of the
traditional methodology and that a failure to make such an adjustment "would
result in a windfall to PSNH."  Public Service Co. of N.H., 82 NH PUC 787,
800 (1997).  Additionally, a correction of $150 million was made to reduce
PSNH's rate base calculation for proper ratemaking treatment of both assets
and liabilities relating to FAS 109 deferred income tax accounts.

     With regard to the Company's cash working capital, Mr. Naylor, in
supplemental testimony filed December 30, 1999, calculated an allowance of
$18.095 million as compared to the $31.369 million included in the Company's
updated rate case filing.  Because there has not been a lead/lag study
relating to PSNH, Mr. Naylor employed the methodology used in the lead/lag
study required by the Connecticut Department of Public Utility Control in
connection with PSNH affiliate CL&P, to determine the lag days of the various
working capital components. According to Mr. Naylor, the CL&P study is
instructive because its operations are similar to those of PSNH and because
the two companies receive common administrative support from NUSCO.  He
further recommends that PSNH be required to conduct a lead/lag study in
connection with its next rate case.

     Mr. Naylor's testimony includes a discussion of the range of possible
outcomes in a rate case proceeding.  In other words, Mr. Naylor analyzes the
probability that Staff's views would prevail in the event a fully developed
rate case were presented to the Commission.  Mr. Naylor begins with the
assumption that it is highly probable the Commission would accept Mr.
Kosnaski's recommendations concerning cost of equity.  In that case,
according to Mr. Naylor, the least likely scenario is that only 50 percent of
the Staff recommended income statement adjustments including those Company
adjustments adopted by Staff, would be accepted.  At hearing, Mr. Naylor
recommended that the depreciation adjustment be maintained at 100 percent of
its value, with the remaining income statements at 50 percent.  This yields a
7.59 percent decrease in the Company's revenue requirement, which Mr. Naylor
suggests would be the low-end of a range of possible rate case outcomes.  In
so characterizing this scenario, Mr. Naylor stresses that Staff's revenue
adjustments are "conservative" and that there were additional adjustments
that Staff could plausibly have recommended but did not.  Mr. Naylor's "high
end" scenario involves the Commission accepting all of Staff's proforma
adjustments, plus certain additional ones, viz: reductions in PSNH's economic
development-related costs, costs related to sheep grazing for transmission
line clearing, amortizing some costs identified in the 1997 rate filing that
may remain in the 1998 test year, proforming the equity component of PSNH's
capital structure to 40 percent, and the potential effects of other dockets
as discussed by Mr. Cannata in his testimony. According to Mr. Naylor, this
"high end" scenario would reduce PSNH's revenue requirement by 12.48 percent.

     However, Mr. Naylor then goes on to testify that his range of rate case
outcomes does not include the recovery of and amortization of the difference
between temporary rates and permanent rates.  Mr. Naylor notes that PSNH's
temporary rates would be effective on July 1, 1997 even though customer bills
were not actually reduced by that amount until December 1, 1997.  Based on
retail revenues of $325.04 million during these five months, Mr. Naylor
calculates that a $22.33 million refund would be due to PSNH's customers.

     Mr. Naylor then goes on to discuss the reconciliation of any permanent
rate back to July 1, 1997, the date established by the Commission for
reconciliation of permanent and temporary rates.  Mr. Naylor notes that, by
reconciling any full permanent rate decrease back to that date, PSNH would be
deprived of certain depreciation expenses it legitimately accrued under rates
previously approved by the Commission.  He also notes that Staff's
recommendations for revenue adjustments are based on a test year that began
three months after July 1, 1997, a deviation from traditional rate setting
practice.

     Therefore, Mr. Naylor would solve the reconciliation problem by applying
a four-step process: (1) analyze the Company's revenue requirement prior to
the test year, (2) analyze the test year itself, (3) consider post-test-year
expenses and (4) account for the amortization of regulatory asset balances
and for depreciation rates.  These calculations yield what Mr. Naylor
characterizes as a range of possible refunds from $135 million to $171.35
million depending on whether the Commission would adopt the "low end"
reduction of 7.59 percent or the recommended reduction of 10.07 percent.

     Mr. Naylor further notes that, in the event the Settlement Agreement is
not adopted, PSNH would be entitled to seek a revised FPPAC rate that would
presumably include the currently deferred FPPAC balance - projected to reach
$103 million by May 31, 2000.  Mr. Naylor agrees with Mr. Cannata that the
only likely adjustment to this balance involves a possible determination of
imprudence related to an outage at Seabrook, which could reduce the FPPAC
balance by $7 million.  According to Mr. Naylor, if PSNH sought full recovery
of the deferred FPPAC balance during the next six month FPPAC period, a rate
increase of about 24 percent would be the result for those six months.  This
would impose a delay in the rate reductions customers would see under a
conventional rate case, Mr. Naylor notes, although he adds that the
Commission could offset this effect by requiring a more rapid return of the
temporary rate reconciliation amounts.

     Finally, Mr. Naylor testifies that conventional rate-setting would
likely lead to an additional rate increase if the temporary rate
reconciliation amounts are amortized into customer rates over a two year
period.  However, he further adds that as of May 2001 the Seabrook Deferred
Return will be fully amortized and thus no longer included in FPPAC rates.
This will more than offset the end of the temporary rate reconciliation
refunds.

B.   RECOVERY OF STRANDED COSTS

1.   Parties other than Staff

     On behalf of the organization Think - New Hampshire, Mr. Jim Rubens
submitted testimony and urged the Commission to impose a "price cap" on
stranded cost charges.  Mr. Rubens believes there is a significant risk that
PSNH will lose large numbers of customers who will opt for small-scale self-
generation technology that Mr. Rubens believes is soon to be readily
available in the marketplace.  According to Mr. Rubens, this will force PSNH
to increase its stranded cost charge per unit of service, leading to a "death
spiral" of escalating rates as customers defect for self-generation.

     BIA generally supports the stranded cost recovery mechanism in the
Settlement Agreement.  However, it characterizes the $0.0379 per kWh average
SCRC as unacceptably high. BIA asks the Commission to revise the process for
setting the SCRC "to immediately reflect any and all benefits that may result
from better than expected fossil/hydro auction proceeds, better than expected
Seabrook auction proceeds, higher wholesale power proceeds, and lower RRB
bond rates."  Direct Testimony of Susan G. Hersey at 11.  Ph. II, Ex. 30.

     Accordingly, BIA asks the Commission to modify the Settlement Agreement
to provide for a reduced amortization period of seven years for the proceeds
of the fossil/hydro asset sales, to reduce the interest rate on the ADIT
balances from the RRB rate to the stipulated rate of return, and to change
the risk-sharing formula such that savings reduce the amount of the SCRC
rather than adjust the Recovery End Date.  BIA additionally asks the
Commission to use the stipulated rate of return to calculate any credits to
PSNH's revenue requirements.

     According to Great Bay, the proposed Settlement Agreement directly
violates RSA 374-F by permitting PSNH to recover certain above-market
investments and obligations, associated with PSNH's generation assets, that
were incurred after the effective date of the legislation.
Great Bay refers specifically to capital additions made in connection with
Seabrook since 1996. Great Bay refers to Exhibit 40 from Phase I, which lists
more than $17.1 million in such capital additions, noting that the exhibit
lists only additions valued at $1 million or more.  According to Great Bay,
the only possible justification for recovery of these investments would be if
they were deemed reasonable measures undertaken to mitigate other stranded
costs.  However, Great Bay asserts that the record is devoid of evidence in
support of such a proposition.

     Invoking the provision of the Restructuring Act calling for
reconciliation of stranded costs "to actual electricity market conditions
from time to time," RSA 374-F:3, XII(d), Great Bay contends that it is
illegal to permit PSNH to recover its Part 3 stranded costs with a fixed rate
of return over a seven-year period as contemplated by the Settlement
Agreement.  In Great Bay's view, exempting the rate of return on Part 3
stranded costs from ongoing Commission review not only violates the
Restructuring Act but also RSA 378:7 (requiring rates that are "just and
reasonable") because there is no legal basis for assuming that the rates will
continue to be just and reasonable for such an extended period.

     The City of Manchester's objections to the Settlement Agreement's
stranded cost provisions are grounded in its support of the recommendations
of Staff Advocates with regard to the level of PSNH's recoverable stranded
costs, the extent to which PSNH's proposed write-off genuinely represents a
financial sacrifice by PSNH and its parent, NU, particularly in light of the
benefits PSNH receives under the Settlement Agreement, and the
appropriateness to defer, if not eschew, Seabrook divestiture.

     SAPL contends that the inclusion of nuclear decommissioning expenses in
stranded cost charges passed on to customers violates both the regulations of
the Nuclear Regulatory Commission and the applicable New Hampshire statute,
RSA 162-F.  According to SAPL, both the federal regulations and the state law
make the owners of nuclear plants, as distinct from ratepayers, responsible
for nuclear decommissioning.

2.   Staff Advocates and Non-Settling Staff

     The first major stranded cost issue raised by the Staff Advocates
concerns Accumulated Deferred Income Taxes (ADIT).  As Staff Advocates note,
ADIT is a liability on a regulated utility's balance sheet that represents
excess payments by ratepayers arising out of the utility's use of different
depreciation schedules for tax and ratemaking purposes.  In a traditional
rate case, ADIT is offset from rate base on a dollar-for-dollar basis and
customers receive a return on the ADIT balance that is equal to the utility's
weighted average cost of capital.  In the Settlement Agreement, however, the
Staff Advocates point out that PSNH would recover on the ADIT balance through
Part 1 stranded costs, with Part 3 stranded costs being credited with an
offsetting return on ADIT calculated using the interest rate on the RRBs.

     According to the Staff Advocates, because the interest rate on the RRBs
is lower than PSNH's weighted average cost of capital, the effect is to allow
PSNH shareholders to retain a portion of the cost savings attributable to
securitization.  The Settling Parties estimate this issue to account for
$22.4 million on a present-value basis and urge the Commission to credit this
sum to ratepayers.

     The Staff Advocates contend that any number of variations on Mr.
McCluskey's retention model, created at the request of various parties to
this proceeding, support his critique of the Settlement Agreement in regard
to Seabrook.  Using the least ratepayer-favorable scenario cited by Mr.
McCluskey involves a 12.53 percent return on equity, applying the PSNH market
price forecast and assuming no increase in Seabrook's capacity, in which case
Mr. McCluskey estimates a $13 million net benefit to customers from not
selling the Seabrook entitlement as called for in the Settlement Agreement.

     The Staff Advocates recommend modifying the Settlement Agreement to
permit recovery of only 50 percent of the unrecovered contract obligations
associated with the recently closed Maine Yankee and Connecticut Yankee
nuclear power plants.  With regard to Maine Yankee, the Staff Advocates note
that certain secondary purchasers of Maine Yankee power reached an
arbitration agreement with the plant owners concerning the prudence of
shutting the plant prior to the end of its license period, cutting the
secondary purchasers' obligations in half.  According to the Staff Advocates,
a separate agreement reached with NHEC actually resulted in a net payment to
NHEC of more than $1.1 million.

     With regard to Connecticut Yankee, the Staff Advocates note that an
administrative law judge of the FERC recently concluded that management's
operation of the plant was imprudent and therefore recommended that
Connecticut Yankee be denied a return on its net unrecovered investment in
the facility.  In the view of the Staff Advocates, the fact that the Maine
Yankee dispute was resolved through arbitration undercuts the notion that any
similar relief to which New Hampshire ratepayers are entitled will inevitably
flow to them by order of the FERC. Conceding that such a result might occur
with regard to Connecticut Yankee, the Staff Advocates nevertheless contend
that a 50-50 sharing of the stranded costs associated with these plants is
appropriate given the significant questions about their prudent operation.

     The Staff Advocates contend that the Settlement Agreement should be
modified to reflect a $78 million reduction in Part 3 stranded costs to
account for (1) a regulatory liability accrued under FAS 109 of $65.6 million
and (2) a $13 million deferred receivable from NAEC. According to Mr.
McCluskey, the deferred FAS 109 receivable is a generation-related regulatory
liability associated with Seabrook and is therefore properly treated as a
stranded benefit to offset stranded costs.  Mr. McCluskey further contends
that the deferred receivable, originally paid by PSNH to NAEC to cover taxes
due on the sale of a portion of the Seabrook Deferred Return, is also a
stranded liability because this tax liability will disappear when the
Seabrook Deferred Return is written off under the terms of the Settlement
Agreement.

     The Staff Advocates contend that PSNH should not be allowed to recover
as stranded costs certain sums associated with agreements between the New
England Power Pool (NEPOOL) and Hydro Quebec.  The agreements at issue
include: (1) a contract requiring NEPOOL members, including PSNH, to purchase
a specified level of energy from Hydro Quebec through August 2000; (2) the
Hydro Quebec energy banking agreement which expires October 31, 2001; and (3)
related Support Agreements, which require PSNH and other New England
utilities to pay costs associated with the transmission facilities used to
move the energy from Quebec to New England.  The Staff Advocates note that
the Settlement Agreement assumes the sale of the energy entitlements and
recovery of the net stranded costs associated with them.

     The Staff Advocates' problem is with the $62 million that the Settlement
Agreement would permit PSNH to recover in stranded costs attributable to the
cost of buying out the Company's payments under the Support Agreement.
According to the Staff Advocates, there is no reason to treat these payments
as generation-related and therefore recoverable as stranded costs.  The Staff
Advocates' view is that these are transmission-related expenses that relate
to extremely high-voltage facilities.  The Staff Advocates point out that the
Connecticut Department of Public Utility Control recently ordered that CL&P's
analogous costs be classified as transmission-related.  Conceding that this
Commission, in Order No. 22,512 (February 28, 1997), determined that PSNH
could recover Support Agreement costs as part of its interim stranded cost
charge, the Staff Advocates nevertheless contend that the most important
factor in classifying this expense as generation-related disappears with the
end of energy importation under the Hydro Quebec energy contract.

     In the alternative, Staff Advocates ask the Commission to determine that
the proposed stranded cost figure of $62 million associated with the Support
Agreement does not reflect adequate mitigation as required by the
Restructuring Act.  In the view of the Staff Advocates, this figure should be
offset by the revenues that could be received for transporting electricity
between New England and Quebec over the Hydro Quebec facilities or from the
sale of the facilities to a new owner.

     The Staff Advocates' final point regarding the Support Agreement
payments is that they should not be removed from stranded costs only to be
included in PSNH's Delivery Charge. According to the Staff Advocates, the
Settlement Agreement assumes that Transmission and Distribution costs are
allocated to customers based on cost causation principles and, because the
Hydro Quebec facilities are not necessary to provide any customers with
Transmission and Distribution services, they should not be recovered through
Delivery Charges.

     The Staff Advocates ask the Commission to remove from the stranded costs
to be recovered in the Settlement Agreement the sum of $4.3 million,
representing 43.8 percent of PSNH's loss on reacquired debt. The 43.8 percent
reflects the ratio of PSNH's non-generationrelated assets to its total
assets, as calculated by Mr. McCluskey.  According to Mr. McCluskey, the
Settlement Agreement improperly allocates PSNH's entire loss on reacquired
debt to generation for purposes of allowing the entire loss to be recovered
through the SCRC.

     Further, relying on the testimony of Mr. Kosnaski of the Commission
Staff, the Staff Advocates are of the view that the Settlement Agreement
allows for at least some double recovery of losses related to reacquired
debt.  According to the Staff Advocates, PSNH witness Mahoney conceded that
there is a double-recovery problem.  The Staff Advocates believe the
Commission should require PSNH to recalculate the SCRC to correct the error.

     With regard to the $5 million of value the Settlement Agreement assigns
to ratepayers in connection with PSNH's interest in the Millstone 3 nuclear
plant, the Staff Advocates contend that the Commission should correct this
sum to account for a likely double-recovery.  According to Mr. McCluskey, the
$5 million figure tracks his 1999 estimate of the value of the interest,
based on the discounted cash flow (DCF) model.  However, Mr. McCluskey
contends that his valuation treats nuclear fuel and Materials and Supplies
inventories as costs that should be recoverable through the market price of
the asset.  Thus, according to Mr. McCluskey, to the extent the Settlement
Agreement's valuation of the Millstone 3 reflects otherwise, it should be
changed.  Mr. McCluskey recommends a $2 million credit to Part 3 stranded
costs for this purpose.

     The Staff Advocates further contend that Part 3 stranded costs should be
modified to correct for what they contend are three modeling errors by the
Settling Parties.  First, the Staff Advocates take the position that the
FPPAC deferred balance should be corrected to reflect an offset for Capacity
Transfer savings in November and December 1999 pursuant to the Rate
Agreement.  Second, the Staff Advocates seek an adjustment that is related to
the 1998 sale of NOx allowances, for which PSNH received $24.5 million and
later spent $13.5 million to fund capital improvements at the Merrimack and
Schiller plants, which the Staff Advocates regard as the equivalent of
customer-contributed capital. The remainder appears on the PSNH books as a
regulatory obligation.

     The Staff Advocates accordingly request a reduction in the estimated
book value of the fossil/hydro assets of $13.5 million and a reduction in
Part 3 stranded costs of $11 million.  Next, the Staff Advocates contend that
the Settling Parties' modeling has incorrectly assumed that in 2000 customers
will receive both the benefits of selling low-cost energy from PSNH's
fossil/hydro assets in the first half of the year plus a full year of the
amortization of the gain on the sale of these assets.  Finally, Mr. McCluskey
contends that the Settlement Agreement understates the value of the FAS 109
regulatory asset associated with the non-securitized portion of the PSNH
acquisition premium that is not being written off.  According to Mr.
McCluskey, this is because PSNH's effective tax rate will increase on
Competition Day from 37.41 percent to 40.2 percent, increasing PSNH's
collections on the FAS 109 regulatory asset.

     On the subject of the return on equity to be applied to Part 3 stranded
costs, Mr. McCluskey adopted the figure originally recommended by Mr.
Kosnaski of the Non-Settling Staff, which was 6.70 percent.  At hearing, Mr.
Kosnaski revised his figure upward to 7.45 percent to account for subsequent
increases in bond rates.  However, the Staff Advocates note that Mr. Kosnaski
also testified that, assuming annual reconciliation of stranded costs, his
7.45 percent figure would likely overstate the return required for the risk
incurred.  Staff Advocates support the annual reconciliation of Part 3
stranded costs; therefore, in their opinion, it is appropriate to use Mr.
Kosnaski's original 6.70 percent return on equity even given the subsequent
increases in bond rates.

     The Staff Advocates propose to modify the Settlement Agreement to
include a mechanism for reconciling stranded costs annually.  They envision a
process similar to the current annual FPPAC reconciliation proceedings.
According to the Staff Advocates, annual reconciliation of the SCRC is more
faithful to the concept of cost-based ratemaking and would have the salutary
effect of eliminating any possibility of balances being deferred for later
recovery.  The Staff Advocates concede their proposal would effectively
abrogate the risk sharing provisions of the Settlement Agreement, but they
contend their proposal is consistent with RSA 369-A:1, X(c), which advises
that electricity prices should reach the regional average "as soon as
practicable."

     Mr. McCluskey testified at hearing concerning the effect on PSNH's
stranded costs of the Company's separate settlement with NHEC, which was
reached after the Settling Parties concluded the agreement at issue in this
docket.  Thus, according to Mr. McCluskey, the Settlement Agreement was
hammered out under the assumption that NHEC would continue to pay demand
charges to PSNH, as ordered by FERC, even after NHEC customers began
receiving their energy service from competitive suppliers.  Mr. McCluskey
also testified that the Settlement Agreement assumed that NHEC customers
would continue to receive their energy from PSNH through June 30, 2000, and
that PSNH would continue to supply energy to the six ski areas that have
entered into special contracts with NHEC.  Ph. I, Ex.  104 at 50.  However,
the settlement between NHEC and PSNH terminated NHEC's requirements contract
with PSNH as of January 1, 2000 in exchange for a payment of $18 million.
Additionally, PSNH is taking an additional write off of $6.2 million and
crediting Part 3 stranded costs with $2 million a year during the 30-month
IDCP.  Further, PSNH's contractual agreement to buy back NHEC's share of the
Seabrook output remains in force until its expiration on June 30, 2000.

     According to Mr. McCluskey, the net effect of the NHEC-PSNH agreement is
to reduce NHEC's contribution to PSNH's stranded costs from $39 million to
$15 million.  He also sees a total of $2 million in transmission revenue
flowing from NHEC to PSNH and, thus, estimates that the NHEC settlement will
increase the stranded costs payable by PSNH customers by $24 million. Beyond
pointing this out, however, the Staff Advocates do not suggest any resulting
modifications to the Settlement Agreement now before us.

     Mr. McCluskey developed a series of unbundled rate projections that he
contends would apply if his recommendations concerning stranded costs were
adopted and the Delivery Charge contained in the Settlement Agreement were in
force.  Mr. McCluskey predicts a 23.3 percent rate reduction in 2000,
followed by small increases in 2001 and 2002, with the average rate
increasing by 10.8 percent in 2003 as Transition Service ends and customers
must seek competitive suppliers.  Thereafter, according to Mr. McCluskey's
projections, the average rate continues to increase but then falls in 2007 by
6.3 percent.  Further rate reductions of 5.7 percent occur in 2008 and 8.6
percent in 2012 as recovery ends for Part 3 and Part 1 stranded costs,
respectively.  This forecast assumes the imposition of a retail adder for
Transition Service as a means of encouraging customers to switch to
competitive suppliers.

     Non-Settling Staff did not take a position on stranded cost issues.

C.   DIVESTITURE AND AUCTION

1.   Parties other than Staff

     With regard to asset sales, Representative Bradley urges the Commission
either to preclude affiliates of both NU and of ConEd from bidding or impose
a strict code of conduct regulating both the sales themselves and all future
interactions among affiliates of NU and ConEd.  He further takes the position
that it is not appropriate for PSNH to administer the sale of its generation
assets in any event and that the Commission should hire a consultant to
conduct the sales under Commission supervision.

     On the subject of municipal acquisition of generation assets, it is
Representative Bradley's view that municipalities should not expect to
acquire such facilities at anything less than market prices as determined
through a competitive bidding process.  Bradley Brief at 5.  The Settlement
Agreement should be modified to permit municipalities more time to complete
such transactions given the approval requirements of RSA 38:3, 4 and 5.
Representative Bradley supports a suggestion, apparently first posited by
PSNH in a data request to the City of Manchester, that (1) bidders for hydro
facilities be required to state a separate price for each asset, thus
establishing a market price, (2) that municipalities be provided with a
period of 90 to 120 days to seek voter approval for payment of such a price
pursuant to RSA 38 and (3) that, in the event of voter rejection, the asset
be sold to the winning bidder.  As an alternative, Representative Bradley
suggests selling the fossil assets in the near term but deferring the sale of
the hydro assets so as to give PSNH more time to reach an agreement with the
affected municipalities.  Id.

     SAPL takes the position that PSNH should divest itself of its Seabrook
obligations immediately, not within three years as contemplated by the
Settlement Agreement.

     With regard to asset divestiture, BIA does not favor precluding PSNH
affiliates from participating in the bidding.  It believes its provision is
consistent with promoting a "robust" bidding process, and further contends
that any concerns about fairness can be addressed by strengthening the
applicable Code of Conduct and through the hiring of an independent party to
conduct the sales.  As to other issues that have arisen in connection with
divestiture (i.e., treatment of environmental liabilities and pollution
credits, asset bundling, employee protection, transmission terms and other
obligations) BIA expresses the general concern that bidders may reduce their
bids unnecessarily based on a perception that the terms of sale are too
onerous.

     Cabletron urges the Commission to revise those portions of the
Settlement Agreement dealing with Seabrook divestiture.  Cabletron's specific
concern relates to the method for setting a minimum bid price.  According to
Cabletron, neither PSNH nor the Settling Staff conducted sufficient analysis
to determine whether recent sales of other nuclear plants are an appropriate
basis for determining the minimum bid.  It is Cabletron's recommendation that
the Commission condition approval of the Settlement Agreement on the opening
of a separate docket for determining the appropriate criteria for setting the
minimum Seabrook bid.  See Cabletron Brief at 5.

     Further, in Cabletron's view, the Commission can and should await the
receipt of bids to provide PSNH Transition Service and then use those market
prices as the basis for conducting a discounted cash flow analysis of when
and how to sell PSNH's Seabrook obligation.  Id.  Cabletron stresses that it
does not oppose the immediate sale of NAEC's ownership interest in Seabrook
and is concerned here only with PSNH's contractual obligation to purchase
Seabrook power.

     Great Bay draws the Commission's attention to the provision of the
Settlement Agreement under which the Commission can force a PSNH affiliate to
pay the minimum bid price or net book value of PSNH generation assets in
certain circumstances.  Great Bay questions whether the Commission could
exercise jurisdiction over the affiliates in order to cause that to happen.
Great Bay Brief at 38-39.

     Great Bay also contends that a failure to address its decommissioning
concerns will result in a substantially lower price for the PSNH Seabrook
interest.  Ph. II, Tr. Day XVI, pp. 8-10, 132-133, 195-199.  Its president,
Mr. Frank Getman, testified in detail on the subject.  He referred to the
state law, 1998 N.H. Laws, Chapter 164, Section 2, that makes the other
Seabrook Joint Owners responsible for Great Bay's decommissioning costs in
the event it is unable to meet them. In Mr. Getman's view, this potential
liability will reduce bid levels unless it is eliminated by assuring that
Great Bay's decommissioning costs are passed along to New Hampshire
ratepayers. Great Bay also posits the risk of its own bankruptcy, contending
that potential bidders will factor such a risk into their offering prices
unless the Commission takes steps to assure that Great Bay's decommissioning
expenses are covered.  And Great Bay makes the argument that the Commission
should act to assist it with its decommissioning liability because this would
be consistent with the Commission's previously expressed concerns about
health and safety in relationship to nuclear power.  Great Bay Brief at 35.

     Great Bay dismisses the notion that it assumed the risk of being in a
more difficult position, vis a vis the other Seabrook Joint Owners, to pay
decommissioning liabilities when it purchased its interest in the plant.
According to Great Bay, it indeed assumed the risk of changes in regulation
but not, it contends, the risk of a

new regulatory regime under which existing players in the market are required
to operate under one set of rules (in this case, funding decommissioning as
an operating expense) while new entrants (i.e., a new competitive supplier
buying NAEC's Seabrook interest) are permitted to operate under different,
more favorable rules.  Brief at 34.

Accordingly, Great Bay asks the Commission to condition the divestiture of
PSNH's Seabrook interest on providing "funding assurance" for Great Bay's
share of decommissioning through a "small increase in the system benefits
charge."  Great Bay Brief at 32.  Great Bay also recommends that the
Commission instruct PSNH and NAEC to negotiate with the other Seabrook Joint
Owners to obtain their contribution to this "funding assurance."  Id. at 33.

     Great Bay's final point about decommissioning is that the relevant
provisions of the Settlement Agreement run afoul of the statutory requirement
that, at the conclusion of decommissioning, any excess funds be used to
adjust rates downward.  Great Bay cites RSA 162-F:20, II as support.

     Mr. Aalto has concerns with the proposed asset divestiture processes.
In his view, PSNH will not reap adequate value for them on behalf of
ratepayers.  He proposes retention of the generation assets, at least for the
present, and operation of them in a manner similar to that proposed in the
Settlement Agreement for the pre-divestiture period.

     OCA asks the Commission to accept Mr. Long's offer to exclude NU and its
affiliates from the process of bidding on PSNH generation assets.  According
to OCA, the Commission should deem Consolidated Edison and its affiliates as
included in such prohibition.  With regard to the Seabrook divestiture, OCA
contends that interested parties should be given the right to provide
"unlimited input" into the process of setting a minimum bid.  OCA also
contends that the State of New Hampshire should retain a right to acquire the
Seabrook interest by matching either the winning bid or the minimum bid.  OCA
offers this as an option to the suggestion that the Commission simply require
PSNH and NU to retain the Seabrook interest.

     NEP and GSEC favor the Seabrook divestiture provisions of the Settlement
Agreement, as opposed to the suggestion advanced by Staff Advocates,
described in detail below, to retain the asset for some additional period of
time in an effort to use its value to reduce stranded costs.

     According to NEP and GSEC, a near-term sale of the PSNH/NAEC Seabrook
interest may tend to maximize benefits to ratepayers by allowing for a
simultaneous sale of Seabrook and the Millstone 3 nuclear power plant in
Connecticut.  Relying on the testimony of Messrs. Cannata and McCluskey, NEP
and GSEC note that purchasers of nuclear power plants may be attempting to
amass "regional fleets" of such facilities in order to achieve efficiencies
and reduce risks.  Brief at 6.  Accordingly, NEP and GSEC contend that some
buyers may only be interested in Seabrook if they believe other similar units
are or will be available.  Further, NEP and GSEC contend that if Seabrook
were to become the last nuclear power plant in New England to be sold, these
"fleet" considerations may limit the viable bidders to those companies that
have already invested in other nuclear assets in the region.  Id.

     NEP and GSEC further contend that a near-term sale of Seabrook could
forestall a loss of value to ratepayers occasioned by the plant's minority
owners selling a controlling interest in the facility without the
participation of NAEC.  They also believe that an earlier sale would reduce
risks to ratepayers by eliminating their liability for Seabrook operating
costs and decommissioning expenses, and by insulating ratepayers from the
possibility of Seabrook becoming an unsalable asset as a result of an
"operational catastrophe" at the facility.

     The Settlement Agreement requires PSNH and NAEC to make all reasonable
efforts to cause other Seabrook Joint Owners to participate in the sale of
the 36 percent interest in the plant represented by PSNH and NAEC.  According
to NEP and GSEC, the Commission should order PSNH to bundle for sale purposes
the interests of all Seabrook Joint Owners who wish to participate in the
divestiture process.  Id.   Further, in the event bundling does not occur,
NEP and GSEC contend it would be appropriate for the Commission to require
NAEC to show cause why bundling was impossible or would improvidently reduce
the sale price and for the Commission to hold PSNH financially responsible
for any imprudent decision not to bundle the PSNH/NAEC interest with other
Joint Owners.   Id. at 7.    NEP and GSEC point out that other Joint Owners,
i.e.,  NEP and the New Hampshire Electric Cooperative, have customers whose
stranded costs are related in part to Seabrook.  According to NEP and GSEC,
potential purchasers of the PSNH/NAEC interest may reduce their bids because
of the risk that other owners could deprive them of control of the facility,
absent a bundled sale.

     In the view of NEP and GSEC, it would be improvident for the Commission
to establish a confidential minimum bid for the PSNH/NAEC Seabrook interest
as contemplated by the Settlement Agreement.  According to NEP and GSEC,
because the Commission has final authority over the sale in any event,
imposing a minimum bid would produce no benefit and would tend only to delay
divestiture, diminish buyer interest in the asset or even act as a price
floor, reducing initial bids.  Brief at 7-8.

     NEP and GSEC argue in the alternative that the Commission should use
market-based methodologies, as opposed to a discounted cash flow (DCF)
analysis, to compute a minimum bid. According to NEP and GSEC, the
Restructuring Act favors such an approach, given its references to
reconciling stranded costs to actual market conditions, and to favoring
marketdriven choice to traditional planning mechanisms.  Further, according
to NEP and GSEC, the DCF analysis favored by Mr. McCluskey of Staff Advocates
makes too many assumptions about future costs and operations, for which his
14 percent discount rate does not adequately account. Brief at 9.  In the
view of NEP and GSEC, simply relying on the competitive marketplace to assess
the present value of Seabrook in light of future risks is more reliable,
especially given that the bidding entities will have conducted extensive due
diligence.  According to NEP and GSEC, slight changes to any assumption in a
DCF analysis can significantly alter the result including the possible
outcome of a large increase in stranded costs.  Brief at 10-11.
Consequently if any of the assumptions underlying the Staff Advocate's DCF
analysis were wrong, Commission reliance on his proposal could lead PSNH
customers to pay increased stranded costs.

     NEP and GSEC make an additional statutory argument against the retention
of the Seabrook asset based on the language of RSA 374-F:3, XII, which sets
out utilities' obligation to "take all reasonable measures to mitigate
stranded costs" and provides that mitigation measures "may include, but are
not limited to, " four enumerated examples: expense reduction, contract
renegotiation, debt refinancing, and the retirement, sale, or write-off of
uneconomic or surplus assets."   NEP and GSEC make the point that retention
of generation assets is not among the mitigation strategies enumerated by
this provision.  Accordingly, they invoke Roberts v. General Motors Corp.,
138 N.H. 532 (1994).  In Roberts, the New Hampshire Supreme Court determined
that the rules of statutory construction lead to the conclusion "that the
phrase 'including but not limited to' . . . limits the applicability [of a
provision using the phrase] to those types of acts therein particularized."
Id. at 538 (emphasis in original).  The implicit point of NEP and GSEC is
that asset retention is not the type of mitigation measure contemplated by
RSA 374-F:3, XII.

     Four towns - Bow, New Hampton, Hillsborough and Gorham - and the City of
Franklin, appeared jointly to raise certain shared municipal concerns in
connection with the Settlement Agreement.  Each of these five municipalities
has expressed interest in acquiring a PSNH hydro facility within its borders,
but believes the relevant provisions of the Settlement Agreement are a
significant impediment to such an acquisition.  Specifically, they contend
that requiring municipal acquisition proposals to be made "without
qualification" runs afoul of RSA 38:13, which establishes a public vote plus
the issuance of a bond and note as preconditions to municipal acquisition.
Likewise, they contend that RSA 38:13 would preclude municipalities
from meeting the Settlement Agreement condition that municipal buyers enter
into binding purchase and sale agreements within ten days of the Commission
order approving the Settlement Agreement.  Additionally, the municipalities
contend that the employee protection provisions of the Settlement Agreement
would either make it too difficult for the municipalities to acquire the
facilities or would increase stranded costs by lowering the prices the
municipalities would be willing to pay.

     The municipalities are also concerned about the language in the
Settlement Agreement giving PSNH the unilateral right to reject any municipal
offer that does not meet or exceed the price PSNH could reasonably expect to
receive as part of the public sale process.  According to the municipalities,
this vests too much discretion in PSNH.  The municipalities disagree with the
testimony of PSNH witnesses Large and McDonald that a city or town may only
acquire a hydro facility if the facility is within its borders.  The
municipalities also object to certain language in the Settlement Agreement
that they contend limits municipal bidders in the regular asset sale to those
that have previously negotiated with PSNH.  Finally, the municipalities
oppose any mandatory groupings of the hydro assets for sale purposes.

     In light of these concerns, the municipalities make several proposals.
First, they request a delay in the sale of the fossil/hydro assets for a
period of four to six months because the power market is "currently out of
equilibrium" with prices too high and because a delay would allow the
municipalities to complete the processes required by RSA ch. 38.  Second,
they request that at the asset sale each bidder be required to state a
separate price for each individual asset that may
be part of a grouped bid.  According to the municipalities, the highest bid
for each individual facility would establish its fair market value, and each
municipality should then be given an opportunity to acquire the asset at that
price.  Then, if the municipality declines this option, the asset would go to
the highest bidder, with the municipality waiving its right to acquire the
facility under RSA ch. 38 for a period of five years as a precondition to
participating in the bidding process.  If the municipality decided to
exercise its option, it would have 60 days to complete the voting and bonding
process set forth in RSA 38:13, barring which the asset would be conveyed to
the highest regular bidder.

     The City of Manchester cites its efforts to acquire the Amoskeag Hydro
facility, located in Manchester, from PSNH.  According to the City, it
expended more than $150,000 conducting due diligence and valuation, made an
offer to PSNH and was told by PSNH that the company valued the facility at
approximately four times the City's offer, which PSNH rejected.  In light of
this experience, the City proposes that the Commission require PSNH and other
similarly situated municipalities to submit to a process whereby the
Commission would perform a binding valuation, whereupon the municipality
would have an absolute option to purchase the facility in question at the
Commission-determined price.  As an alternative, the City suggests binding
valuation by an arbitration panel selected by the parties to the transaction.
The City also finds unacceptable those provisions of the Settlement Agreement
allowing PSNH to bundle hydro assets for sale purposes, requiring putative
municipal purchasers to make their offers subject to no contingencies,
protecting employees of the hydro assets after their sale and requiring
municipalities to enter into a binding purchase agreement within ten days of
the Commission's approval of the Settlement Agreement, with the sales closing
within 60 days.

     The other municipalities do not agree with certain positions taken by
the City of Manchester.  Specifically, they believe that the Commission lacks
jurisdiction under RSA 38 to employ the mandatory asset valuation process
advanced by Manchester as an alternative to the municipal acquisition
provisions of the Settlement Agreement.  Further, the municipalities disagree
with the argument of Manchester and the City of Berlin concerning the
reference to small-scale hydro facilities in RSA 38:32.  They point out that
the Commission has previously decided in Order No. 23,250 (November 22, 1999)
that this reference does not permit a municipality to short-circuit the voter
approval regime in RSA 38 while still availing itself of the chapter's
valuation and condemnation procedures.

     The City of Concord appears to assert its interest in the fate of PSNH's
Garvins Falls Site, which PSNH has identified as a potential location for a
generation facility and which PSNH proposes to divest pursuant to the
Settlement Agreement.  According to the City of Concord, the site is within
its "Garvins Falls Urban Reserve Area" and has been thoroughly investigated
by the City with regard to development possibilities.  The City of Concord
asks the Commission to direct PSNH to require the City's "active
participation" in the development of criteria for selling this parcel.  The
City requests an "equal vote to that of PSNH, the PUC, or [any] third party"
participating in the development of the relevant sale criteria.  City of
Concord Brief at 5.

     SAPL urges the Commission to order Seabrook divestiture immediately upon
the approval of the Settlement Agreement or any other plan for PSNH
restructuring.  In SAPL's view, Seabrook continues to lose value as its
components age and, thus, the proceeds of the sale can only decrease over
time.

     CRR supports the early divestiture of PSNH's Seabrook interest.  CRR
believes that any effort to increase the Seabrook rate of return if the asset
is not sold by the end of 2002 creates a "perverse and improper incentive"
for NU and its affiliates to delay the Seabrook divestiture. Brief at 6.  CRR
further urges the Commission to preclude NU, Consolidated Edison and their
affiliates from retaining, acquiring or reacquiring PSNH generation assets.
In the alternative, CRR asks the Commission to order that the sale process be
managed by an entity that is independent of NU and Consolidated Edison.  CRR
calls for a mechanism to provide a "reasonable and workable opportunity" for
municipal acquisition of generation assets, but provides no details.

2.   Staff Advocates and Non-Settling Staff

     Staff Advocates indicate support for the proposed buy-down of NAEC's
investment in the Seabrook plant, the establishment of a minimum bid for the
facility and Commission oversight of the sale.  However, Staff Advocates
contend that establishing the minimum bid based on comparable transactions
will tend to undervalue the plant.  Therefore, Staff Advocates recommend that
the Commission modify the Settlement Agreement to reserve the right to
establish a minimum bid based upon an administrative valuation of Seabrook.
As a possible source of that administrative valuation, Staff Advocates offer
Mr. McCluskey's analysis.

     The Seabrook divestiture plan advanced by Staff Advocates would call on
PSNH to retain its Seabrook entitlement until either the facility is closed
or until the market for nuclear assets produces a bid that meets the
administratively determined minimum level.  According to Staff Advocates,
this option would reduce recoverable stranded costs by $137 million more than
the plan to sell Seabrook by the end of 2003 for $100 million.

     Staff Advocates describe several reasons for believing that the Seabrook
asset is undervalued, including the interest of only 2 companies, Entergy and
AmerGen, in acquiring nuclear assets and that the relatively low prices paid
for nuclear assets are a function of the perceived risks associated with
nuclear power.  According to the Staff Advocates, rather than accept this
market reality as a "fact of life," the Seabrook contract should be retained
as "a valuable hedge against the risk of nuclear asset prices falling
significantly below their true worth." Conceding that the Commission has
previously expressed, in its Final Restructuring Plan, a preference for
market-based determinations of asset value, the Staff Advocates nevertheless
contend that a departure is warranted here given the serious questions about
the market's ability "to deliver anything close to the asset's true worth"
and that retention of Seabrook fulfills the PSNH obligation to mitigate
stranded costs.  Brief at 9-10.

     According to the Staff Advocates, the market price forecast used by Mr.
McCluskey in his testimony, supplied by Mr. Douglas Smith, is the only such
forecast in the record and stands unrebutted. Further, they contend that Mr.
McCluskey reasonably used a 14 percent discount rate to arrive at an estimate
of the present value of the Seabrook revenue stream.  According to Staff
Advocates, Mr. McCluskey simply took the standard 10 percent discount rate
for utilities and added 400 basis points to account for the particular risks
associated with nuclear power.  The Staff Advocates further contend that Mr.
McCluskey's retention option would still result in a net benefit to
ratepayers of $67 million compared to a sale in 2003, even if one applies a
20 percent discount rate to arrive at present value figures.  Brief at 12.

     In estimating the revenue requirements for the Seabrook contract, Mr.
McCluskey generally relied on PSNH's data.  According to Staff Advocates, the
only disputes that arose in this regard concerned Mr. McCluskey's estimates
for Operations & Maintenance, a possible increase in the Seabrook plant
capacity and the issue of return on equity.  With regard to Operations &
Maintenance expenses, Staff Advocates dispute the view that expenses will
inevitably increase as the plant ages.  According to Staff Advocates,
expected improvements in plant management could actually reduce Operations
and Maintenance costs and, in any event, the contrary is already accounted
for in the 14 percent discount rate.  With regard to plant capacity, Staff
Advocates contend there is no dispute that the Seabrook Joint Owners received
advice from a consultant that an increase in rated capacity was both feasible
and economic.  According to Staff Advocates, to disregard that potential in
these circumstances would be inconsistent with the stranded cost mitigation
requirement of the Restructuring Act.  Finally, Staff Advocates contend that
Mr. McCluskey may have actually understated the benefit of retaining the
Seabrook contract because he modeled a 12.53 percent return on equity in 2000
and assumed an 11 percent return on equity beginning in 2001.  According to
Staff Advocates, there is no basis for assuming an increase in PSNH's return
on equity in the Seabrook retention scenario because nuclear risks are
already taken into account in the Commission Staff's recommendation of a 9.65
percent equity return in connection with PSNH's transmission and distribution
operations.

     Staff Advocates reject the notion that retaining the Seabrook contract
risks saddling PSNH ratepayers with higher decommissioning costs than they
would sustain under the Settlement Agreement.  According to the Staff
Advocates, nothing in the record supports an inference that the Nuclear
Decommissioning Finance Committee has underestimated the cost of
decommissioning Seabrook.  Further, the Staff Advocates contend that, because
a potential Seabrook purchaser would discount the bid price to reflect the
risk of higher-than-expected decommissioning expenses, the risk itself should
have no impact on the choice between retention and sale.  Brief at 16.

D.   TRANSITION SERVICE

1.   Parties other than Staff

     According to Representative Bradley, it is not in the public interest
for the Commission to permit PSNH to price Transition Service in a manner
that creates significant deferrals that will be added to recoverable stranded
costs, particularly in light of the prohibition on exit fees contained in RSA
369-A:1, XI.  However, he also contends that, because the public expects an
18 percent reduction in PSNH rates, it is important to achieve that level of
reduction without relying on deferrals.

     According to Representative Bradley, Exhibit 107 of Phase I of the
proceedings articulates a hypothesis of Settling Staff that Transition
Service costs that are higher than those assumed in the Settlement Agreement
could result in a net decrease to the stranded costs borne by ratepayers
because higher market prices for energy will also raise expected revenues
from market sales of Seabrook, SPP and fossil/hydro power as well as higher
proceeds from the sale of PSNH's generation assets.  Representative Bradley
disagrees, contending that it is contradicted by the results achieved in
Maine.  He states that the advent of new generation facilities in New England
could also adversely affect the assumptions in Phase I, Ex. 107.  He compares
the assumptions in Ex. 107 to the assurances provided by NU at the advent of
the Rate Agreement about the likely relationship of PSNH rates to average
rates in New England.  According to Representative Bradley, if the Commission
were to adopt such a view of the likely relationship between the cost of
Transition Service and stranded costs associated with generation assets, it
is not fair to require ratepayers to bear the full risk underlying the
hypothesis contained in Ex. 107.   In Representative Bradley's view,
requiring PSNH to bear the risk that the retail price of Transition Service
is too low would likely cause PSNH to suggest a more "reasonable and
sustainable" price for such service.

     Representative Bradley also comments on a suggestion by the State
signatories to the Settlement Agreement, articulated in Phase II, Exhibit
180, that it may be appropriate to use PSNH's generation assets to provide
Transition Service prior to their divestiture, thus delaying the acquisition
of Transition Service from other sources.  According to Representative
Bradley, this is appropriate in principle but, without more realistic retail
prices for Transition Service, would still tend to retard the development of
a competitive retail electricity market.  Brief at 10.

     THINK-NH contends that the Commission may not approve the Settlement
Agreement in its present form because the record lacks evidence that the
proposal will lead to retail competition among a range of viable retail
electricity suppliers for at least several years.  In its view, the
Transition Service charge must be priced at a minimum of $0.045 per kWh in
order to meet what it characterizes as a legal requirement of retail
competition.  Brief at 3.

     With regard to Transition Service rates, BIA estimates the deferrals
associated with the levels initially proposed in the Settlement Agreement to
be approximately $60 million to $120 million.  BIA opposes to any such
deferrals, arguing that by setting Transition Service rates at levels that
are below market prices the Commission may hinder the development of a
competitive market.

     Cabletron indicates that it agrees with many of the positions taken by
Representative Bradley.  In particular, Cabletron contends there should be no
deferrals associated with Transition Service, other than those associated
with "minor system efficiencies associated with system and EDI true-ups," and
that the Commission should rule out the use of retail adders.

     Cabletron recommends that the Commission can and should await the
receipt of bids to provide PSNH Transition Service and then use those market
prices as the basis for conducting a discounted cash flow analysis of when
and how to sell PSNH's Seabrook obligation.

     Great Bay characterizes deferrals associated with Transition Service as
"illegal stranded costs."  In Great Bay's view, such deferrals involve the
creation of an "inverse uneconomic generation asset":  rather than buying
power at above-market prices, PSNH would be achieving the same effect by
selling power to retail customers below market levels.  Great Bay Brief at 5.
Great Bay urges the Commission not to permit any such deferrals.

     Mr. Aalto believes that PSNH should be required to obtain Transition
Service through the spot and short-term energy markets of ISO-New England, as
opposed to a process of entering into requirements contracts.  According to
Mr. Aalto, this will actually lower costs to consumers because the suppliers
of energy under requirements contracts would have to factor the risk of load
losses into their bids.

     According to OCA, the Transition Service provisions of the Settlement
Agreement run afoul of the Legislative determination that "[i]ncreased
customer choice and the development of competitive markets for wholesale and
retail electricity services are key elements in a restructured [electric]
industry..."  RSA 374-F:I.  Relying on the testimony of one of its witnesses,
Dr. Richard A. Rosen, of Tellus Institute, a consulting firm, as well as that
of Mr. Ray Morrison of the New Hampshire Consumer Utility Cooperative
(NHCUC), OCA contends that the Transition Service proposal will not lead to
retail competition.  According to OCA, these witnesses demonstrated that
"aggregated groups of retail customers" will be the force behind retail
competition and, without their meaningful participation in the market,
wholesale generators will exert market power and raise prices unnecessarily.

     According to OCA, Dr. Rosen's testimony demonstrates that line losses
and load factors mean the cost of providing wholesale Transition Service
varies by customer class by up to 6 mils per kWh.  Thus, the Commission
should require PSNH to seek separate Transition Service bids for each
customer class and adjust the Stranded Cost Recovery Charge accordingly, so
as to provide each class with the same percentage reduction in rates.

     To stimulate the aggregation that OCA believes is key to creating retail
competition, it proposes "short-term subsidies" to electricity retailers for
the last of the three-year period covered by the Transition Service
provisions of the Settlement Agreement, to take effect if less than 15
percent of residential customers have not chosen a competitive supplier 18
months into the period.  Relying on Dr. Rosen's estimates, OCA asks the
Commission to require PSNH to impose retail "adders" to Transition Service
rates of between $0.008 and $0.012 per kWh.  In support of this position, OCA
invokes one of the 15 policy principles in the restructuring statute,
specifically the "systems benefits charge" authorized by RSA 374-F:3, IV.
This provision authorizes such a charge "to fund public benefits related to
the provision of electricity."   According to OCA, competition is a public
benefit and thus can be funded through such a mechanism.  OCA concedes there
is no "clear quantitative analysis" in the record of this proceeding that
demonstrates that ratepayers would receive a long term net benefit if the
Commission imposed a retail adders in such a fashion.

     With regard to the Transition Service price before the imposition of any
retail adder, OCA invokes another of the policy principles in the
restructuring statute:

Choice for retail customers cannot exist without a range of viable suppliers.
The rules that govern market activity should apply to all buyers and sellers
in a fair and consistent manner in order to assure a fully competitive
market.  RSA 374-F:3, VII.

According to OCA, a Transition Service price that is below the market price
for such service violates this exhortation to fairness and consistency.

     Noting that it administered an aggregation program during the
restructuring Pilot Program, the City of Manchester expresses the concern
that the provisions of the Settlement Agreement governing Transition Service
will improvidently inhibit the development of a competitive retail
electricity market.  The City of Manchester urges the Commission to take
administrative notice that analogous prices in the service territory of
United Illuminating have ranged from $0.042 per kWh to $0.050 per kWh, and
contends that PSNH's own estimates show that the average wholesale price of
Transition Service is $0.042 per kWh, citing Dr. Rosen's testimony on behalf
of the OCA, Ph. II, Ex. 56C, 3.  Manchester Brief at 25.

     Freedom Partners, L.L.C. is a potential competitive supplier of retail
electricity in PSNH's service territory, contends that the record compels the
Commission to find the Transition Service rates proposed in the Settlement
Agreement are far below market levels, a situation that will cause the
"arguably unlawful" result that PSNH customers will not be able to choose
alternative suppliers after Competition Day.  Freedom Partners appears to
accept as a given that the Commission will not opt for a retail adder for
Transition Service so as to encourage the development of a competitive market
for electricity.

     Accordingly, Freedom Partners urges the Commission to address
forthrightly these Transition and Default Service pricing provisions of the
Settlement Agreement that make it extremely unlikely that small and medium-
sized customers will be able to switch to competitive suppliers during the
transition period.  See Freedom Partners Brief at 3.

     The New Hampshire Consumers Utility Cooperative (NHCUC) urges the
Commission not to adopt the aspects of the Settlement Agreement pertaining to
Transition Service.  According to the NHCUC, the proposed Transition Service
rates are clearly below market levels and would result in "unfair power price
competition."  NHCUC notes that competitive suppliers incur overhead costs
related to customer acquisition, EDI (electronic data interchange) services,
customer service, billing and bad debts, which are in excess of 5 mils per
kWh for residential and small commercial customers.  According to NHCUC,
combining these costs with the reality of below-market Transition Service
prices yields insurmountable obstacles for potential competitive suppliers of
electricity to PSNH customers.

     Accordingly, NHCUC proposes two alternatives.  The first is a retail
price adder  of 8 to 10 mils per kWh, to be subtracted from the SCRC of all
customers and added to the energy charges paid by customers taking Transition
or Default Service.  NHCUC concedes this will cause a shortfall in stranded
cost collections, but offers that the Commission could compensate for this
loss by extending the stranded cost recovery period.

     NHCUC's second alternative entails PSNH providing certain free services
to promote the development of a "cooperative, non-profit and municipal
aggregation sector."  Their proposal calls for PSNH to: permit aggregators to
obtain power from the Transition Service provider at the Transition Service
price; provide billing, EDI and customer services to the non-profit and
municipal aggregators; and pay a subsidy of 2 mils per kWh to the
aggregators.  In addition, NHCUC proposes that the number of customers
eligible to receive service from such aggregators be limited.

     NHCUC expresses concern with the provision of the Settlement Agreement
that, at the end of the transition period, would assign customers who failed
to choose a competitive supplier to the successful bidder(s) for Transition
Service.   According to NHCUC, this would be anticompetitive because it would
allow the supplier to gain customers without incurring any acquisition costs.
Finally, NHCUC asks the Commission to require PSNH to set up a fund of $3
million to provide grants and low-interest loans to non-profit aggregators.

     According to NHCUC, this proposal has several advantages: no effect on
stranded cost recovery, no rate increases for customers who do not choose a
competitive supplier and the development of a market sector for customers
that some energy suppliers have not deemed attractive customers.  NHCUC
further contends that the development of a vibrant aggregation
sector will provide a benchmark for evaluating offers by competitive
suppliers of electricity, and will facilitate the development of "rapidly
emerging intelligent technologies".

     SOHO/CAP are opposed to the imposition of retail adders for the purpose
of stimulating competition in the residential market.  According to SOHO/CAP,
such a strategy may subsidize inefficient suppliers at the expense of the
near-term rate relief principle described in RSA 374-F:3, XI. and may also
cause large customers to avoid using Transition Service, thus potentially
undermining the prescription of equitable customer benefits described in RSA
374-F:3, VI.

     CRR agrees with the other parties that believe it is likely if not
certain that the Transition Service pricing provisions of the Settlement
Agreement will result in significant deferrals. According to CRR, because the
Transition Service load is likely to be at or near 100 percent of PSNH's
customer base, this deferral may exceed $150 million.  CRR Brief at 2.
However, CRR disagrees with those parties who have suggested that an
appropriate modification is simply to raise the retail price of Transition
Service.  According to CRR, such a change in the Settlement Agreement would
tend to decrease further the rate relief that, in CRR's view, is already
below the level generally expected to be achieved through restructuring.
CRR's proposal is that PSNH be precluded from recovering the difference
between the Transition Service price and the actual cost of providing this
service.  Brief at 3.

2.   Staff Advocates and Non-Settling Staff

     Neither Staff Advocates nor Non-Settling Staff took a position with
respect to Transition Service.  Testifying on behalf of Staff Advocates, Mr.
Doug Smith stated that while the range of plausible forecasts of wholesale
energy prices included the so-called Sabatino forecast, to which the Settling
Parties referred to support their proposed Transition Service rate path, more
likely forecasts of wholesale prices were somewhat higher.

E.   SECURITIZATION

1.   Parties other than Staff

     According to Representative Bradley, pursuant to RSA 369-A:1, X, the
Legislature has declared that securitization should provide certain customer
benefits.  Among those benefits are reductions in the costs to customers
associated with six wood-burning power producers and one trash-to-energy
plant that currently have contracts with PSNH.  RSA 369-A:1, X(g) points to
"[f]urther renegotiations" with the owners of these facilities.
Representative Bradley, asserts this goal has not been met, the
renegotiations have not been pursued and appropriate efforts should be
undertaken immediately.  In his view, if such renegotiations generate
additional customer savings it may be appropriate to securitize certain up-
front costs of any buy-downs.  According to Representative Bradley, it would
be a "complete victory for all parties" if, absent IPP buydowns prior to
implementation of the Settlement Agreement and further monetary provisions by
PSNH, the Commission were to determine that PSNH and its customers should
share any net savings from IPP buy-downs or IPP-related restructurings that
are finalized after implementation of the Settlement Agreement.  See Bradley
Brief at 14.

     In order to permit securitization of costs associated with IPP buy-
downs, Representative Bradley believes the amount of other stranded costs to
be securitized should be reduced by $75 million to $650 million.  He deems
the $75 million to be approximately equal to the proposed amount of the
acquisition premium to be amortized and believes it should be amortized over
12 years, limited to the rate of return in the Settlement Agreement, and
subject to risk sharing in years 7 through 12.

     Another suggestion of Representative Bradley to increase near-term
customer savings without deferrals is to reduce and cap the system benefits
charge.  Noting that GSEC overcollected in connection with its low-income
program, he concludes that a similar overcollection could occur with PSNH
under the present terms of the Settlement Agreement.

     BIA characterizes the securitization provisions of the Settlement
Agreement as acceptable. In BIA's view, securitization "appropriately
advances the interests of all PSNH ratepayers."

     In the view of Great Bay, the Settlement Agreement as seriously flawed
because it fails to deal with the issue of nuclear decommissioning in what
Great Bay characterizes as an "evenhanded way."  Brief at 26.  Great Bay
refers to how the Settlement Agreement makes an ongoing cost, decommissioning
of Seabrook, a stranded cost.  According to Great Bay, this creates an
"operating subsidy" for the entity that purchases PSNH's Seabrook interest,
to the disadvantage of Great Bay - which, as an exempt wholesale generator,
is not in a position to require ratepayers to pay its share of
decommissioning expenses.  According to Great Bay, this runs afoul of those
portions of the Restructuring Act that address the development of a
competitive electricity marketplace.

     Mr. Aalto strongly objects to securitization.  He disputes the
underlying assumption that securitized costs are ones that customers would be
required to pay in any event.  According to Mr. Aalto, securitization means
"[t]he customers would effectively buy-out the utility without getting
title."  He contends that the appropriate mode for causing ratepayers to
guarantee payment of PSNH obligations is for them to buy the utility
outright.

     Among Mr. Aalto's objections to the Settlement Agreement is his view
that it relieves NU of too much business risk through asset write-downs that
will flow from PSNH to NU as a result of securitization.  According to Mr.
Aalto, NU is avoiding this risk at the same time that PSNH is itself becoming
more vulnerable to a possible second bankruptcy in the future as a result of
load losses.

     On the subject of securitization, OCA does not oppose the concept per
se, calling it a zero sum game for ratepayers.  OCA's concern is that the
Commission authorize securitization only for those costs that ratepayers
would have had to absorb in any event.  Therefore, it is OCA's view that the
Commission should complete the PSNH Rate Case and other stayed dockets to
determine with precision which of PSNH's stranded costs should be borne by
ratepayers.

     CRR also expresses serious reservations about securitization.  According
to CRR, the Settlement Agreement relies too heavily on securitization to
achieve rate relief.   It believes the Commission should require PSNH to seek
savings from other sources instead, such as a reduction in the amount of
stranded costs PSNH may recover or what CRR characterizes as "truly capturing
the efficiencies of a competitive market."  CRR Brief at 4.   According to
CRR, securitization threatens to dampen the development of technology that
will allow ratepayers to avoid taking power from the PSNH transmission and
distribution system.  In CRR's view, this is a possibility because, in the
face of customers going off-line and thus avoiding the payment of stranded
cost recovery charges, PSNH is likely to take further action to protect the
securitized revenue stream.

     The City of Manchester supports the concept of securitization but
believes the amount proposed under the Settlement Agreement is far too high.
According to the City, the securitization provisions of the Settlement
Agreement would provide PSNH with such a large cash infusion as to give it an
unfair competitive advantage, particularly in light of the proposed ConEd
merger.  The City contends that PSNH's desired debt-equity ratio can be
achieved with a much lower level of securitization.  Ph II, Ex. 35 at 7.  Mr.
Kury also expressed concern about securitizing the SFAS 109 amount of $44
million related to the Acquisition Premium since it is not due from
ratepayers until the Acquisition Premium is actually amortized.


2.   Staff Advocates and Non-Settling Staff

     Mr. Kosnaski testified that securitization offers real benefits to the
ratepayers of PSNH, through direct and indirect effects.  By replacing higher
cost debt and equity with Triple-A rated, tax deductible debt, securitization
provides financing and tax savings that can provide lower rates. Mr. Kosnaski
also states that the Commission consider requiring the Company to use the
proceeds of securitization to meet the target equity ratio of 40 percent
discussed by Mr. McHale in his prefiled direct testimony and deemed
appropriate in order to earn an investment grade rating on the Company's
debt.  Mr. Kosnaski notes that although Mr. McHale discusses the 40 percent
equity ratio as appropriate, an examination of Mr. McHale's financial
projections shows that the equity ratio actually averages 47.5 percent in the
year 2000.  Mr. Kosnaski testified that requiring PSNH to meet Mr. McHale's
target equity ratio would yield a net savings of $3.6 million in 2000, adding
0.50 percent to the original 18.3 percent rate reduction.

F.   NU MERGER WITH CONSOLIDATED EDISON

1.   Parties other than Staff

     On the subject of the proposed merger of NU and ConEd, Representative
Bradley urges the Commission to clarify in this docket that merger-related
"synergy" savings should flow to ratepayers via a long-term freeze in
distribution rates or even decreases in such rates.  He notes that the
securitization aspects of the Settlement Agreement will materially help the
merging parties realize the perceived value of the merger.

     Representative Gilmore urges the Commission to require NU and ConEd to
share with PSNH ratepayers both the acquisition premium to be paid to NU
shareholders by ConEd as well as any savings achieved as a result of the
merger.

     According to Mr. Aalto, it is appropriate for the Commission to
determine that the proposed merger between NU and ConEd is not in the public
interest.  Mr. Aalto's view is that the merger presents no benefits to
consumers in the form of economies but nevertheless poses "the possibility
that a very large company will possess enormous market power and have the
ability to influence without control, legislation and regulation."

     OCA urges the Commission to take up the question of NU's planned merger
with ConEd in the context of this docket.  According to OCA, it is an
accepted principle of utility accounting that gains and losses on the sale of
utility assets are charged to investors rather than ratepayers. Therefore,
according to OCA, because PSNH's ratepayers are assuming responsibility for
some of these losses through stranded cost recovery, it is consistent with
symmetry and equity to require NU to share what OCA characterizes as the
stranded benefits of the ConEd merger.  According to OCA, the SCRC should be
reduced to account for these stranded benefits, the Commission should reserve
the right to reduce PSNH's delivery charge during the initial period to
account for merger-related savings, and the Commission should make clear in
this proceeding that the door is closed with respect to whether ConEd could
ever recover from New Hampshire ratepayers any portion of the acquisition
premium associated with the proposed NU merger.

     Further, OCA draws the Commission's attention to the testimony of NU
Chairman and Chief Executive Officer Michael Morris that, following ConEd's
merger with NU, and subsequent to planned divestitures of generation assets,
ConEd plans to control only 2,000 megawatts of generation capacity out of
75,000 megawatts of capacity in ISO-New England and the New York Power Pool.
According to Mr. Morris, this includes approximately 500 megawatts of new
capacity planned by one of ConEd's unregulated subsidiaries.  OCA asks the
Commission to limit the new company's ownership of generation assets to the
level described by Mr. Morris.

     With regard to all of the issues related to the merger, OCA contends the
Commission must address these concerns now or risk having PSNH and/or NU
argue in the merger proceeding itself that the issues are foreclosed by the
decision in this docket.

     According to the City of Manchester, there is a "troublesome"
relationship between the timing of the Settlement Agreement and the timing of
the merger agreement between NU and ConEd.  Noting that NU has acknowledged
that it began merger discussions with ConEd on June 30, 1999, and pointing
out that by then PSNH had already entered into the MOU that led to the filing
of the Settlement Agreement in August 1999, the City believes NU should have
made all the Settling Parties aware that such merger talks were under way.
According to the City, if the parties to the Settlement Agreement had known
that such a merger agreement was in the offing they might well have insisted
that it be addressed explicitly in the Settlement Agreement.     In the
City's view, the provision that did get into the Settlement Agreement
concerning a possible sale of PSNH's assets does nothing to protect the
public, at least in the context of the proposed merger because the sharing
provision applies to a transmission and distribution asset sale only.  The
City's contention is that "a good argument can be made" that the proposed
merger is really an asset sale that triggers the sharing problem.  Brief at
36.  Further, the City contends that even if the assetsale sharing provision
applied to the proposed merger, it would be inadequate, because PSNH
ratepayers who are being called upon to compensate PSNH for its stranded
costs, they deserve more than one-third of any proceeds beyond 1.5 times book
value, derived from the sharing formula that would apply in an asset sale.
Brief at 37.

     The City urges the Commission to use this docket as an appropriate
occasion to determine that RSA 374-F requires NU's selling shareholders to
share with PSNH ratepayers any gains they reap in connection with the ConEd
merger, given the ratepayers' liability for PSNH's stranded costs.  According
to the City, this result is justified by the language in RSA 374-F:4,V
requiring any stranded cost recovery charge to be "equitable, appropriate and
balanced," as well as the New Hampshire Supreme Court's decision in Appeal of
City of Nashua, 121 N.H. 874 (1981).  In the City of Nashua case, the Court
agreed with the Commission that appreciated real property could be removed
from a utility's rate base at original cost, thus allocating the gain to
stockholders, because any loss on the sale of the land could not have been
charged to ratepayers.  City of Nashua, 122 N.H. at 877.

     In other words, the City's position is that under RSA 374-F and City of
Nashua the NU-ConEd acquisition premium is simply the other side of the
equation that permits PSNH and NU to impose stranded costs on their New
Hampshire ratepayers.  Further, the City maintains that the Settlement
Agreement permits PSNH to recover twice on the same transmission and
distribution assets - once through traditional ratemaking that allows for a
return of and on the assets and again through the receipt of an acquisition
premium from ConEd.

     The City further draws the Commission's attention to the language in the
Settlement Agreement providing that if NU is acquired or otherwise sold or
merged within five years of Competition Day, the Commission shall approve the
transaction "only if it be shown to be in the public interest."  The City's
view is that this is a stricter standard than the "no net harm" test the
Commission has generally adopted for reviewing utility mergers over which it
has jurisdiction. The City's final point about the proposed merger is that
the Commission should determine here that ConEd will in no circumstances ever
be permitted to recover any portion of the NU acquisition premium that it
allocates to PSNH.

     With regard to the proposed NU/ConEd merger, CRR urges the Commission
not to defer the issue and to determine now that ratepayers are entitled to a
claw back mechanism that will assure that ratepayers benefit from the
proposed acquisition.  According to CRR, it would then be appropriate for the
Commission to defer the issue of what precise amount ratepayers ought to
realize from the merger transaction.

2.   Staff Advocates and Non-Settling Staff

     The Staff Advocates ask the Commission to consider the implications of
the proposed acquisition of NU by ConEd in the context of this docket and
determine here that the acquisition premium being paid by ConEd must, at
least in part, be credited to ratepayers as an offset to stranded costs.
According to the Staff Advocates, such an approach is justified in light of
the provisions of the Restructuring Act that require a balancing of interests
between utilities and ratepayers; stranded cost recovery that is equitable,
appropriate and balanced; and requiring all reasonable measures to mitigate
stranded costs.

     Relying on the testimony of Mr. LaCapra of the Staff Advocates as well
as that of Messrs. Kury, Antonuk and Mr. Long, the Staff Advocates take the
position that, just as restructuring has led to the existence of stranded
costs that are charged to ratepayers, so does the same process of
restructuring account for industry consolidation in general and Consolidated
Edison's plan to acquire NU in particular.  The example offered by the Staff
Advocates is the use of the facilities of a transmission and distribution
utility for telecommunications; they note that NU, through a subsidiary, is
part owner of a 900-mile fiber optic network being constructed in New York
and New England that utilizes NU subsidiary rights of way.

     According to Staff Advocates, corporate opportunities of this sort exist
solely because of restructuring.  In the view of the Staff Advocates, "where,
as here, a single cause both adds and subtracts value to utility assets,
there must be a symmetrical allocation of the resulting benefits and burdens
between ratepayers and shareholders."  Staff Advocates Brief at 41-42.

G.ENVIRONMENT AND SYSTEM BENEFITS

1.   Parties other than Staff

     Representative Bradley took no position on environmental issues or
system benefits, except to reduce and cap the system benefits charge as one
option to keep the target 18.3% rate reduction while still increasing
Transition Service charges to more realistic levels.  See Bradley Brief at
13.

     Mr. Aalto stated that properly functioning markets provide adequate
incentives for energy efficiency.  However, he believes that subsidies for
energy efficiency may be appropriate for a limited time.  He contends that
the appropriate agency to operate such energy efficiency programs is GOECS,
not utilities.

     With regard to environmental issues, OCA urges the Commission not to use
this proceeding to impose stricter emissions requirements on PSNH's
generation assets.  According to OCA, such action would improvidently drive
up stranded costs and the subject is more properly left to either the
Legislature or the Department of Environmental Services.  On the related
subject of the environmental remediation fund described in the Settlement
Agreement, OCA believes it is unfair to require ratepayers to absorb all
prudently incurred remediation costs that exceed the sums being set aside in
the fund.  OCA asks the Commission to cap ratepayer liability for
environmental remediation at the same level as that for which PSNH has agreed
to be liable via the reserve fund.

     SAPL urges the Commission to require PSNH to cause its presently-
operating Newington, Schiller and Merrimack generation facilities to comply
with emissions standards for newly built coal and oil-fired power plants.  In
addition, SAPL contends that the Settlement Agreement, as drafted, violates
applicable federal and state law relating to nuclear decommissioning.

     According to SAPL, the Commission should revisit its previous
determination, Final Plan at 116-117, that it will not set emissions
standards for electric generation facilities.  SAPL believes such
reconsideration is appropriate in light of Governor Shaheen having gone on
record in October stating that she does not favor the imposition of new
controls on fossil fuel plants because such action would jeopardize the
settlement process.  In SAPL's view, given the Governor's position, it falls
to the Commission to impose such standards - particularly in light of
RSA 374-F:3, VII, which establishes "[c]ontinued environmental protection and
long term environmental sustainability" as one of the policy principles of
electric restructuring.

     BIA urges the Commission to scrutinize the proposed SBC because it adds
significant costs to electricity prices.  In particular, BIA believes the
portion of the charge associated with demand-side management may be too large
because BIA believes PSNH will not be able to ramp up such a program so
quickly.  However, BIA supports the portion of the SBC that relates to low-
income programs.

     According to CLF, energy policy in New Hampshire has been characterized
historically by attempts to reduce rates in the short term, with much less
attention paid to reducing the overall costs to society of energy production
in the long term.  In asking the Commission to use this proceeding to chart a
different course, CLF invokes the language in RSA 374-F:3, VIII instructing
the Commission that "[o]ver time, there should be more equitable treatment of
old and new generation sources with regard to air pollution controls and
costs."  Characterizing this policy prescription as environmental
comparability, CLF contends it requires the Commission to require PSNH's
fossil plants to reduce their emissions to levels comparable to those
required of new plants.  In CLF's view, to do otherwise will subvert
competition in the power generation market by giving existing, high-emission
power plants an unfair advantage over new facilities.

     CLF disagrees with PSNH's view that existing emissions trading programs
adequately meet the environmental objectives articulated in RSA 374-F:3,
VIII.  According to CLF, the programs invoked by PSNH were in existence at
the time RSA 374-F was enacted and, thus, the Legislature could not have
intended those programs to meet the environmental improvement objective
articulated in the restructuring statute.  In any event, according to CLF,
these programs are inadequate because they will not achieve the goal of
environmental comparability.  CLF takes exception to PSNH's view that
environmental comparability will increase stranded costs by reducing the sale
prices of the fossil assets.  CLF concedes that this is possible, but is not
inevitable and may not be significant.

     CLF accuses PSNH of seeking to deflect attention from its own high-
emission fossil plants by pointing to high emissions rates among facilities
in the Midwest.  CLF's point is that midwestern generators contribute
relatively little to air pollution in New England and, because of technical
limitations in the transmission system, will not be significant players in
New England's wholesale electricity marketplace.  Therefore, according to
CLF, there is no reason to compare PSNH's fossil assets to those in the
midwest in deciding to impose new emissions controls here.

     The remaining issue CLF raises concerns the provision in the Settlement
Agreement calling for funding energy efficiency programs at a level of up to
$0.0025 per kWh in the third year after Competition Day, unless the
Commission makes a different decision in considering the recommendations of
the Energy Efficiency Working Group.  CLF supports the funding level in the
Settlement Agreement and urges the Commission simply to adopt it here without
leaving room for further revision in another docket.

     CRR endorses the proposals of SAPL and CLF to require PSNH's fossil
generators to meet the emissions standards of newly constructed plants.

H.   RECLASSIFICATION OF TRANSMISSION AND DISTRIBUTION ASSETS

1.   Parties other than Staff

     With regard to reclassification of transmission and distribution assets,
Representative Bradley expresses the concern that PSNH might use such
reclassification to extract increased transmission service prices from the
three New Hampshire municipalities that presently operate generation
facilities as well as other municipalities that may acquire such facilities
in the future.

     Representative Gilmore contends that PSNH's witnesses have refused to
respond to his queries or those of Representative Bradley concerning how the
proposal to reclassify transmission and distribution assets would affect
municipally owned utilities.  He also expresses the concern that
reclassification may make it more difficult for IPP's to sell their power,
thus undermining the value of hydroeletric assets and retarding the
development of independent providers of renewable energy.  Representative
Gilmore, therefore, urges the Commission to reject the reclassification
provisions.

     Great Bay takes exception to the Settlement Agreement's failure to
unbundle PSNH's transmission and distribution rates.  In particular, Great
Bay draws the Commission's attention to the testimony of PSNH witness Long,
who stated that he did not know "when and if and how [unbundling of
transmission and distribution rates] could happen."  According to Great Bay,
such unbundling is required by various provisions of the Restructuring Act,
viz: RSA 374-F:3, III ("When customer choice is introduced, services and
rates should be unbundled to provide customers clear price information on the
cost components of generation, transmission, distribution, and any other
ancillary charges"); RSA 374-F:3, IV ("Non-discriminatory open access to the
electric system for wholesale and retail transactions should be promoted.");
RSA 374-F:4, I (Commission should unbundle distribution, transmission and
generation rates "at the earliest practical date").

     Mr. Aalto does not agree with the proposed reclassification of
transmission and distribution assets and believes the Commission should adopt
a different methodology for calculating delivery service charges.  An
appropriate methodology would, in Mr. Aalto's view, do more to take into
account the likelihood that significant numbers of customers will be
generating their own electricity.

     With regard to transmission and distribution service, Freedom Partners
invokes the Commission's rehearing order in connection with the Final
Restructuring Plan, Re Electric Utility Restructuring, 83 NH PUC 126 (1998).
In the rehearing order, the Commission requested the cooperation of New
Hampshire electric utilities in developing retail transmission tariffs at the
state level, noting that, "[i]n the absence of cooperation, we will take such
action as is necessary to ensure that retail competition is not blocked by
utilities denying customers access to appropriate transmission services."
Id. at 144 (also noting that, apart from FERC regulation of transmission
tariffs, "electric utilities in this State possess no vested right to operate
a monopoly franchise free from the imposition of new standards or conditions
which are specifically designed to promote free and fair competition in the
retail market for electric services).

     According to Freedom Partners, the bundled Delivery Charge proposed in
the Settlement Agreement is inconsistent with these Commission determinations
and would improperly prevent customers from arranging for transmission
service directly under the Open Access Transmission Tariff that FERC has
approved for all of the NU system.  In the view of Freedom Partners, the
Settlement Agreement improperly requires customers who do not use PSNH's
distribution system to pay distribution charges.  Freedom Partners
characterizes the bundled delivery rate as an "unlawful tying arrangement."

     Relying on the testimony of Non-Settling Staff witnesses Naylor and
Kosnaski, Great Bay takes the position that the proposed delivery rate is
excessive. (FN 19)  Further, Great Bay contends that the delivery rate
calculated by Mr. Naylor (which involved a range of $0.0267 to $0.0275) would
be even lower if Mr. Naylor had applied the actual PSNH capital structure
that will be in place during the IDCP, rather than PSNH's historical capital
structure.  According to Great Bay, this future PSNH will have a
significantly lower equity component and no preferred stock, thus reducing
the company's cost of capital.  According to Great Bay, making this
adjustment yields a delivery service charge of between $0.0251 and $0.0262,
assuming the 60/40 debt-to-equity ratio to which Mr. McHale testified as
PSNH's target.  Citing Appeal of Conservation Law Foundation, 127 N.H. 606,
636 (1986), Great Bay contends that the Commission has a well-established
authority to utilize a hypothetical capital structure for a utility when
setting its rates.

     According to Great Bay, certain provisions of the Settlement Agreement
could permit PSNH to recover an excessive return in connection with the
delivery charge during the IDCP. Great Bay refers to the provisions
permitting PSNH to seek adjustment of the delivery charge to reflect
regulatory or other legal changes or modifications to applicable accounting
rules.  In Great Bay's view, the relevant language requires the Commission to
make such adjustments if requested, without any room for the Commission to
consider PSNH's total cost of service.

     Great Bay urges the Commission to reject the proposed $0.028 per kWh
delivery rate during the IDCP as excessive.  According to Great Bay, it is
clear that the Settling Parties agreed upon this rate to permit PSNH to
recoup some of its write-offs.  In the view of Great Bay, the Commission
cannot approve such a compromise because the proposed delivery rate was not
arrived at in accordance with accepted ratemaking principles.

     Invoking the so-called Anti-CWIP statute, RSA 378:30-a, Great Bay takes
the position that the delivery service charge must be rejected because the
Settling Parties have produced no evidence that PSNH will not be recovering
construction work in progress (CWIP)through this charge.  Further, Great Bay
contends the record is similarly devoid of evidence that the plant for which
PSNH seeks recovery meets the "used, and useful" standard of RSA 378:28.
According to Great Bay, the Restructuring Act does not authorize the
Commission to approve a delivery rate outside of the traditional ratemaking
process as a convenience to resolve the issues.

     OCA explicitly declines to take a position on the propriety of the
proposed average delivery service charge of $0.028 per kWh.

     The City of Manchester also expresses concerns about the proposed
Delivery Service Charge. According to the City, there is a substantial risk
that PSNH will overearn on this charge if it is implemented and fixed for 30
months as contemplated by the Settlement Agreement.  The City notes that
PSNH's bundled rates have not been subjected to the scrutiny of a rate case
for ten years and, if the Settlement Agreement is implemented, there will be
no such scrutiny of unbundled delivery charges for another three years.
This, according to the City, "creates a serious void in the record upon which
the Commission is to make a public interest finding."

     With regard to the level of the Delivery Charge, the City agrees with
Mr. Naylor's recommendation to the effect that $0.026 per kWh is a more
appropriate rate.  The City further contends that, in calculating the
Delivery Charge, PSNH has used an equity ratio that is far in excess of its
post-restructuring target of 40 percent equity, thus inflating its cost of
capital.  The City points out that the Delivery Charge, as presently
proposed, may involve new plant additions, which the City contends
transgresses the statute precluding rate recovery for Construction Work in
Progress, RSA 378:30-a.

     Finally, the City contends that the Delivery Service Charge provisions
of the Settlement Agreement are fatally flawed because they preclude any
adjustment for savings achieved through the proposed merger of NU and ConEd.
In short, the City's position is that the record provides clear and
convincing evidence that PSNH will over-recover if permitted to assess the
proposed Delivery Service Charge for the IDCP as contemplated.

2.   Staff Advocates and Non-Settling Staff

     Through testimony, the Non-Settling Staff questions the assumptions
underlying the proposed delivery charge.  Specifically, the Commission's
Finance Director, Mark Naylor, notes that the proposed delivery charge is a
negotiated rate based on PSNH's expected costs, and may not have been
developed using the traditional approach of analyzing historic cost of
service.  Mr. Naylor also contends that setting rates in this manner raises
the possibility that plant additions not yet placed in service are reflected
in the rate, which implicates RSA 378:30-a, the prohibition on the inclusion
of construction work-in-progress (CWIP) in rate base.  According to Mr.
Naylor, the Commission must satisfy itself that the delivery charge provides
for the recovery of only PSNH's cost of service as of the date the charge is
first imposed.

     Mr. Naylor further contends that PSNH's proposed average delivery
service charge of $0.028 per kWh during the initial 30 months following
Competition Day is somewhere in a range of $0.0267 per kWh to $0.0275 per kWh
after applying some proforma adjustments.  He believes this range more
accurately represents what is likely to be PSNH's cost to provide delivery
service during the IDCP.

     Mr. Naylor reached this conclusion by beginning with historical
information from 1996, 1997 and 1998 and determining what the delivery
service rate would have been for an unbundled delivery company, with certain
adjustments to account for the gross receipts tax and the major ice storm
that struck New Hampshire in 1998.  Mr. Naylor also incorporated a 9.65
percent cost of equity, as recommended by Mr. Andrew Kosnaski, Staff's cost-
of-capital expert, whose figure is 135 basis points below the equity rate of
return used by PSNH in calculating the delivery rate in the Settlement
Agreement.  Next, Mr. Naylor adjusted for certain proforma adjustments to
expenses, as would be appropriate in a rate case analysis, as well as
adjustments to depreciation expense as recommended by Staff's depreciation
witness, James Cunningham.  Finally, Mr. Naylor applied the revenue
requirement yielded by these calculations to the average of PSNH's expected
sales in 1999 and 2000, as reflected in Mr. Mahoney's testimony.  This
yielded Mr. Naylor's figure of $0.026 per kWh as presented in his direct
testimony.  At hearing, Mr. Naylor provided a further adjustment to
depreciation expense as detailed by Mr. Cunningham, and an estimate for the
incremental costs associated with using a forecast sales level as part of the
calculation of his original average delivery rate of $0.026 per kWh.  This
created the starting figure for his range of $0.0267 per kWh.  The high end
of the range, $0.0275 per kWh, resulted from using the 1998 sales level and
the revenue requirement presented in his prefiled testimony and adding the
depreciation expense adjustment.

     Mr. Naylor also applied an alternate methodology in his direct testimony
that also resulted in the same figure of $0.026 per kWh.  According to him,
this involves analysis of both historic and forecast data contained in the
testimony of Mr. Mahoney, PSNH's manager of revenue requirements, and
introduced as Exhibit 39 of the Phase I hearings.  Mr. Naylor applied certain
adjustments to Mr. Mahoney's figures:  a more rapid decrease in generation-
related employee salary and payroll taxes, a proforma adjustment to
depreciation expense in conformity with Mr. Cunningham's recommendations, an
adjustment to property taxes that Mr. Naylor contends is appropriate in light
of PSNH's September 30, 1999 monthly financial report, and the application of
the cost of equity recommended by Mr. Kosnaski.  However, Mr. Naylor
indicated that he believes the initial analysis, based on historic rather
than forecast data, is more reliable than the methodology applied in
analyzing Mr. Mahoney's data because the latter is based on what Mr. Naylor
characterizes as a "forward-looking test year."

     Mr. Naylor's ultimate conclusion is that PSNH is likely to overearn on
its delivery service at the proposed rate of $0.028 per kWh during the
initial 30 months after Competition Day.  He specifically disagreed with Mr.
Mahoney's assertion that PSNH would need to reduce its O&M expenses in order
to achieve a reasonable rate of return.  Indeed, according to Mr. Naylor,
significant cuts in expenses and/or significant growth in revenue would
exacerbate the overearning problem.

     With regard to depreciation accrual rates for transmission and
distribution assets, Non-Settling Staff, through its witness James
Cunningham, recommends approval of the accrual rates contained in PSNH's 1997
depreciation study, adjusted to reflect a ten-year life extension.  Non-
Settling Staff further recommends that the Commission not allow PSNH to
amortize easements, given the uncertainty of predicting the useful life of
such assets.

     In addition, they recommend deviating from the 1997 depreciation study
with regard to the deactivation date for Unit 1 of PSNH's Merrimack Station.
According to Non-Settling Staff, the planned deactivation date of 2002 is not
warranted in light of recent capital expenditures in connection with the
unit.  Non-Settling Staff recommends a deactivation date of 2005.

     Mr. Cunningham also recommends that PSNH not be permitted to include the
estimated cost of dismantling its steam production plant assets in its
depreciation accrual rates.  According to Mr. Cunningham, this is appropriate
because PSNH is divesting these assets prior to their dismantlement.
Accordingly, Non-Settling Staff believes these costs are properly borne by
the purchaser or purchasers of these facilities.

     Staff disagrees with PSNH's views concerning amortization for certain
General Plant Accounts: 391, 393, 394, 395, 397 and 398.  Staff recommends
deferral of any decision to allow amortization (vs. depreciation) pending its
review of "high volume/low dollar value" statistics. PSNH proposes reduced
lives and increased depreciation expenses for accounts 391, 394, 395 and 398;
Staff believes that industry average lives are the appropriate benchmarks in
the absence of documentation in support of PSNH's view.  For the same reason,
Staff opposes PSNH's proposal to reduce salvage values for General Plant
Accounts 391 and 394 to zero.

     If the Commission approves the reclassification of PSNH's 34.5 kV
facilities from transmission to distribution assets, Staff recommends an
increase in depreciation expenses of $166,440 to reflect the
reclassification.

     Staff urges the Commission to require PSNH to conduct a new depreciation
study, to be incorporated in the rate case that would be filed at the end of
the IDCP.  If PSNH agrees, Staff recommends that the Commission allow PSNH to
recalculate depreciation accrual rates annually based on the Company's annual
Capital Recovery Study.  If PSNH does not agree to conduct a new depreciation
study, then Staff recommends the Commission order that the rates it approves
as part of the Settlement Agreement be deemed fixed rates until the
completion of such a new depreciation study.

     Finally, Mr. Cunningham recommends that the Commission order PSNH to
book the Commission-approved rates effective with the Commission order in
this case.  Alternatively the Commission could order that the new approved
depreciation accrual rates become effective upon legislative approval of the
securitization plan.  Otherwise, Mr. Cunningham avers, the Commission order
would constitute a "hollow shell" resulting in a condition allowing PSNH to
mask its true earnings by roughly $2.1 million annually for Transmission
Plant and $7.0 million annually for Distribution Plant.

I.   COST ALLOCATION AND RATE DESIGN

1.   Parties other than Staff

     On the subject of rate design, BIA's expressed concern relates to
whether it is possible over the long term to sustain the principle
articulated in the Settlement Agreement that the average rate reduction for
residential customers should equal the average rate reduction for the other
customer classes.  According to BIA, after the end of the IDCP there could be
major changes to rates based on revised costs of transmission and
distribution service, as well as changes to the SCRC.  This, according to
BIA, poses a significant risk to the state's business community. BIA's other
concern about the SCRC is that the $0.0379 per kWh average rate is "not
indicative of the SCRC rate for each class of customers."

     BIA objects to OCA's support, expressed through its witness Mr. Traum,
for exit fees. According to BIA, exit fees are precluded by two provisions of
the Restructuring Act: RSA 369-A:1, XI ("end users shall continue to have the
opportunity to generate electricity for their own use without an exit fee")
and RSA 374-F:3, XII(D) ("entry and exit fees are not preferred recovery
mechanisms").

     Finally, with regard to the new charges proposed by PSNH for late
payments, line extensions, etc., BIA believes the revenues associated with
these charges should be reflected in the calculations supporting the proposed
delivery service charge at the conclusion of the IDCP. BIA proposes in the
alternative that the new fees be deferred until the end of the IDCP.

     As an alternative to not allowing deferrals of Transition Service costs,
Cabletron argues that the Commission should not require payment of deferral-
related stranded costs by customers who do not contribute to such deferrals.
In Cabletron's view, doing so would be unfair and not doing so would have the
salutary effect of encouraging customers to seek service from competitive
suppliers of electricity.

     Invoking certain testimony of PSNH witness Shuckerow, Great Bay contends
that PSNH is improperly seeking to avoid prudence review of its marketing of
its power output prior to divestiture.  Mr. Shuckerow testified that PSNH
seeks to avoid "Monday morning quarterbacking" of its sales efforts.  In
Great Bay's view, the Commission should reject any effort by PSNH to avoid a
full review on prudence grounds of such activities.

     On the subject of special contracts, RSA 378:18-a provides that,
notwithstanding any other law, an electric utility may not "recover from
other ratepayers the difference between the regular tariffed rate and the
special contract rate, unless and only to the extent that the Commission
determines that it is the public interest and equitable to other ratepayers."
According to Great Bay, the Settlement Agreement would impose precisely such
a recovery on PSNH's regular customers but the Settling Parties failed to
present any evidence from which the Commission could make the requisite
determination under RSA 378:18-a.

     Mr. Aalto contends that the SCRC as designed will discourage customers
from investing in energy efficiency measures.

     OCA supports the cost allocations among the various rate classes
contained in the Settlement Agreement that generate the $0.028 per kWh
average delivery charge rate.  With regard to rate design issues in
connection with the SCRC, OCA invokes the Commission's determination in its
1997 Final Restructuring Plan that utilities should "allocate recoverable
stranded costs to all customer classes using existing cost allocation
methodologies for generation assets."  OCA Brief at 7; Final Plan at 68.
According to OCA, the Commission should apply this allocation methodology to
each of the assets that comprise PSNH's stranded costs, as reflected in
Appendix C to the Settlement Agreement.  In that regard, OCA notes that the
so-called "Seabrook Over-Market Generation Assets" reflect costs that are
presently recovered through the FPPAC and related BA charges.

     Noting that the FPPAC rate is equal for all customer classes, and
contending that the same is true for the BA rate, OCA's position is that the
portion of the SCRC attributable to the Seabrook Over-Market Generation
Assets should also be allocated equally among the customer classes.
According to OCA, the same logic applies to the stranded costs identified by
PSNH as Seabrook Deferred Return (NAEC), Seabrook Deferred Return (PSNH),
Deferred SPP Costs, Deferred FPPAC Costs, part of the Deferred Vermont Yankee
and Hydro Quebec Contract Payments and all of Market Value of Wholesale Power
Contracts.  According to PSNH, stranded costs associated with the acquisition
premium paid by NU when PSNH emerged from bankruptcy should also be allocated
equally among the customer classes because these costs are Seabrook-related.

     With regard to costs associated with securitization, OCA's position is
that across-theboard cost allocation is appropriate because the associated
rate reductions are apportioned equally among the customer groups.  OCA
contends that residential ratepayers should receive a proportionally higher
percentage of credit against stranded costs than other customers in
connection with PSNH's divestiture of its fossil/hydro assets.  According to
PSNH, this is because residential customers currently cover a larger
proportion of the costs associated with these assets.

     Finally, OCA expresses the concern that PSNH may negotiate Special
Contracts in the future that would shift additional stranded cost obligations
to residential customers.  Therefore, OCA asks the Commission to allocate
stranded costs among the customer classes now, on a permanent basis.

     With regard to other rate design issues, OCA opposes the elimination of
the Elderly Discount but is "willing to discuss eligibility transfer
criteria," does not oppose the advent of latepayment charges as long as
ratepayers are suitably educated and the resulting revenues are reflected in
the calculation of PSNH's overall revenue requirement, supports a delayed-
phase out of the so-called "humped" residential rate and urges the Commission
to open a separate docket to consider the issue of Field Collection Charges.

     Finally, OCA objects to the provisions in the Settlement Agreement that
permit Special Contract customers to pay what OCA characterizes as $0.01 per
kWh toward stranded cost recovery when other ratepayers must contribute
$0.0379 per kWh.  OCA directs the Commission's attention to its own
conclusion in the 1997 Final Restructuring Plan, viz:

[I]t is inequitable to require captive customers to pay not only their
allocated share of stranded costs but also the share allotted to customers
who are fortunate enough to have realistic energy supply alternatives.
Accordingly, to the extent unbundled special contracts contain lower stranded
cost charges than the charge in the regular unbundled tarrifed rate, we
direct utilities to credit the total annual revenue shortfall to the revenue
side of the stranded cost recovery account . . . .

Re Statewide Electric Utility Restructuring Plan, 82 NH PUC 122, 162 (1997).

     SOHO/CAP recommend that the Commission require the retention of the so-
called "humped" residential rate during the IDCP and deferral or rejection of
certain PSNH rate design
proposals, specifically the elimination of the elderly rate discount and the
imposition of late fees, field collection charges and increased connect and
reconnect fees.

     SOHO/CAP point out that the Commission adopted the "humped" residential
rate design in 1981 in order to make electricity more affordable and also to
promote energy conservation. According to SOHO/CAP, the record here
affirmatively demonstrates that the elimination of the humped rate will have
a disproportionately negative impact on low-income customers, who tend to use
less electricity than other customers.  Further, SOHO/CAP aver that PSNH's
data shows that, under its proposed rate design, the rate relief for
customers who use 250 kWh per month is 7.45 percent and 4.61 percent for
customers receiving the elderly discount.

     With regard to the elderly discount, SOHO/CAP point out that, of the
approximately 2,700 customers receiving service under the discounted rate,
approximately half are between 80 and 90 years old and half are at least 90.
Responding to PSNH's suggestion that low-income customers in this rate class
can enroll in the energy assistance program, SOHO/CAP express concern about
what they characterize as senior citizens' reluctance to enroll in what they
perceive to be a public assistance program.

     Concerning PSNH's proposals for field collection charges, late payment
charges and increase fees for connections and reconnections, SOHO/CAP believe
it is appropriate for the Commission to defer these issues to another docket.
Noting that these proposals are not contained in the Settlement Agreement
itself, SOHO/CAP suggest that these rate design issues have not received the
full attention and scrutiny they deserve.  To the extent the Commission
decides to take up these issues here, SOHO/CAP contend that new fees
undermine the statutory principles of near term rate relief and
affordability.  Invoking the testimony of Ms. Panori, SOHO's witness,
SOHO/CAP take the position that most low-income customers who are in arrears
on utility bills are failing to pay because they are unable to do so, not
because they choose not to pay.  Thus, SOHO/CAP contend, additional charges
designed to discourage late payment will not have the desired effect and only
exacerbate the underlying affordability problem.  With regard to the proposed
field collection charges, they point out that it may not be just and
reasonable to impose such fees on customers who have legitimate difficulties
with the logistics of paying their utility bills.

     SOHO/CAP infer from the testimony of PSNH's witnesses, particularly that
of Mr. Mahoney, that a significant motivation of PSNH in seeking the proposed
new charges is to make up some of the revenue shortfall it expects to arise
out of the Settlement Agreement. According to SOHO/CAP, PSNH's figures show
that the proposed charges could generate $2 million of an expected shortfall
of $10 million.  However, SOHO/CAP point out that Mr. Naylor believes no such
shortfall will exist, thus making the additional fees unnecessary.

VII.   POSITIONS OF THE SETTLING PARTIES:

A.   Settling Staff and Governor's Office
      of Energy and Community Services

     The members of the Commission Staff who participated in the settlement
negotiations (Settling Staff), as well as the Governor's Office of Energy and
Community Services (GOECS)(together, the State Team), urge the Commission to
approve the Settlement Agreement without changes.  In their view, the
Settlement Agreement is in the public interest and the Commission should not
risk failure of the agreement by seeking to impose any additional terms.

Recovery of Stranded Costs

     The State Team believes the Settlement Agreement is good for ratepayers
because it would make New Hampshire the first state to realize a significant
disallowance of a utility's stranded costs.  They point out that PSNH will be
the first New Hampshire utility not to receive essentially full recovery of
its stranded costs.  According to the State Team, full recovery of stranded
costs has been the norm across the country.

     The State Team urges the Commission not to modify the Settlement
Agreement so as to change the allowed return on those stranded costs that
PSNH does recover.  According to the State Team, a weighted average of the
returns on the various stranded cost components under the Settlement
Agreement is 7.57 percent or 7.8 percent if the RRB's are excluded from the
calculation.  The State Team contends these figures are far below the similar
returns allowed utilities in other states, which they peg at 10 to 11
percent.  With regard to the proposed 8 percent return on Part 3 stranded
costs, the State Team recognizes that Staff  witness Kosnaski recommends 7.45
percent, but argues that this difference is not sufficiently material to
"jeopardize the settlement" in light of its other financial benefits.  As did
PSNH, the State Team takes exception to Mr. Kosnaski's determination that the
risks of non-recovery inherent in the Recovery End Date were not relevant in
his computation of the risk premium associated with the
return on stranded cost recovery.  The State Team also points out that Mr.
Kosnaski has conceded it would be necessary to revise his figure upward if,
as in the Settlement Agreement, there were no provisions for revisiting the
approved rate of return if economic circumstances differ from those that have
been assumed.  See State Team Brief at 13.

     The State Team believes the Settlement Agreement provisions regarding
the Seabrook divestiture, RRB interest rates and load growth require PSNH to
take material risks that the Commission should consider when deciding whether
to approve the plan.  According to the State Team, PSNH agreed on an assumed
market value of $100 million for NAEC's Seabrook share even though recent
comparable sales suggest an amount roughly half that figure.  The State Team
calculates that this translates to a risk that the Recovery End Date could be
shortened by 5 to 7 months.  Further, the State Team points out that the
Recovery End Date does not change if the interest rate on the RRB's exceeds
the assumed 7.25 percent - and PSNH would have 20 fewer days to recover Part
3 stranded costs for each 25 basis points by which the RRB's interest rate
exceeds 7.25 percent, regardless of their issue date.  See State Brief at 14.

     Additionally, the State Team directs the Commission's attention to the
fact that load growth may exceed the 2 percent figure used to calculate the
Recovery End Date.  It concedes that higher-than-predicted load growth
lessens the risk to PSNH, but notes that ratepayers also gain by faster
payment of stranded costs.  The State Team posits that investors will
perceive as risky, the fact that PSNH must incur significant load growth to
meet projections for stranded cost recovery.

     The State Team asks the Commission not to impute a rate of return for
Accumulated Deferred Income Taxes (ADITs) at the stipulated rate of return
for PSNH rather than at the rate of return for the Revenue Recovery Bonds, as
called for in the Settlement Agreement.  According to the State Team, this
approach is the "mathematical equivalent" of how Staff  witness Kosnaski
treated the effect of securitization on PSNH's weighted cost of capital
generally.  Further, according to the State Team, changing this aspect of the
Settlement Agreement would be inappropriate because, even when the Revenue
Reduction Bond return is applied to the ADITs, PSNH customers still save
significant sums on the overall rate of return.  Thus, according to the State
Team, it would be "unbalanced" to impute the stipulated rate of return to the
ADITS because that would "seek[] to retain all the favorable return items
that the State Team succeeded in getting PSNH to concede in negotiations,
while reversing the single one that some erroneously argue is more
advantageous to PSNH than what traditional regulatory practice suggests."

     The State Team criticizes the BIA's suggestion to modify the Part 3
stranded cost recovery mechanism to reflect any better-than-predicted
proceeds from the sale of PSNH's fossil/hydro assets more immediately.
According to the State Team, "BIA relies on an unfittingly truncated analysis
of the economic effects of a near-term SCRC reduction."  See State Team Brief
at 16.  The State Team points out that lowering the SCRC in the first seven
years results in increasing the SCRC during the remainder of the 12 years
over which the RRB's are amortized.

     The record contains two energy price forecasts: one, prepared by PSNH
and relied upon in the Settlement; the other, prepared by Mr. Douglas Smith,
a witness for the Staff Advocates, who believes energy prices will be higher
than PSNH does.  Although the State Team notes there is "more similarity than
difference" between them, because the energy price forecasts are used to
estimate stranded costs, the State Team believes the goals of restructuring
are better served by adopting the Settlement Agreement's calculation of the
SCRC as the baseline.  If Mr. Smith's forecast's are correct, the date on
which stranded costs will be fully recovered simply advances. On the other
hand, the State Team asserts that if the Commission recalculated the SCRC
based on Mr. Smith's forecast and the PSNH forecast proved more accurate, the
consequences would be more dire:  increased SCRC charges and/or a longer
period of Part 3 stranded cost recovery.

Transition Service and Rates

     The State Team contends that the Transition Service charges reflected in
the Settlement Agreement are "within a range of reasonable outcomes" over the
transition period  and thus, not inevitably destined to create significant
deferrals associated with PSNH's cost of acquiring this service.  Further,
the State Team draws the Commission's attention to the testimony of Mr.
Michael Cannata, the Commission's Chief Engineer, who believes that the
effect on stranded costs of higher wholesale energy prices could well be
offset by increases in what PSNH would receive in the market for its Seabrook
and IPP obligations and the energy from its fossil/hydro plants.  See Ph. I,
Ex. 107; State Team Brief at 20.

     Nevertheless, like PSNH, the State Team expresses a willingness to
modify the Transition Service aspects of the Settlement Agreement.  The State
Team proposes that PSNH supply Transition Service out of its current
generation portfolio for an interim period (perhaps 6 to 12 months) after
Competition Day at a price of $0.037 per kWh, followed by a competitive
solicitation and bidding process to serve customers at the ceiling prices
established in the Settlement for the remainder of the Transition Service
period.  See Ph. II, Tr. Day XVIII, p. 76; Ph. II, Ex. 180.  According to the
State Team, ensuing years will see certain wholesale pricemoderating
influences take hold: the placing of ISO-New England on an "even keel" in
contrast to the start-up difficulties that the State Team views as
responsible for price spikes in the summer of 1999, and the addition of
significant new gas-fired generation capacity to the regional wholesale
electricity market.

     Consequently, the State Team proposes delaying the procurement of
Transition Service from outside suppliers until the sale of PSNH's fossil
assets, with both transactions taking place at the same time.  This would
facilitate suppliers' linking bids for Transition Service to offers to
purchase some or all of the fossil assets, an option the State Team believes
is appropriate and potentially value-maximizing for ratepayers.

     While supporting the concept of retail competition, the State Team asks
the Commission not to compromise the Restructuring Act's goal of near-term
rate relief in the name of competition.  According to the Settling Parties,
raising the price of Transition Service will not automatically create vibrant
activity in the retail market or lead to widespread customer election
of competitive suppliers.  The Settling Parties urge the Commission to view
Transition service as a short-term "glidepath" to retail competition, to be
viewed in the larger context of the purposes of the Restructuring Act.

     The State Team opposes the recommendations of OCA and the NHCUC to
implement a retail adder for Transition Service in order to encourage
competitive suppliers to provide retail alternatives.  According to the State
Team, a prime reason for restructuring is that regulation is no longer viewed
as an effective way to control costs.  Therefore, the State Team reasons, it
would be "the worst irony to attempt to create a competitive market by a
regulatory-imposed surcharge that would cover a competitor's transaction
costs and profits - at the expense of the rate reductions that restructuring
is supposed to bring."

Transmission and Distribution Service and Rates

     The State Team notes that the members of the Settling Staff conducted
its own analysis of Delivery Service rates to supplement those of PSNH and
Staff witness Naylor.  According to the State Team, its analysis included a
10 percent return on equity and an equity ratio of 40 percent, in contrast to
the higher returns and equity ratios used by PSNH.  Thus, according to the
State Team, although PSNH's calculations produced a revenue deficiency, its
analysis supports the proposed Delivery Service rate of $0.028 per kWh while
using similar assumptions to those of Mr. Naylor in recommending $0.026 per
kWh.  Therefore, the State Team contends Mr. Naylor's analysis provides no
basis to adjust the Delivery Service rate downward.

     The State Team also offers a critique of Mr. Naylor's methodology that
is similar to the one presented by PSNH.  The State Team notes that it
divided its adjusted 1998 costs by 1998 sales, whereas Mr. Naylor used 1999
sales.  The State Team questions Mr. Naylor's assertion that the incremental
cost of serving new load is lower than the fully allocated cost of serving
existing load.  According to the State Team, it "requires speculation to
conclude that growth has or will come cheaply to PSNH".  State Team Brief at
27.  The State Team calculates that, once Mr. Naylor's figures are adjusted
to match costs and sales, his rate differs from that in the Settlement
Agreement by only $0.0008, a difference that can be further narrowed by
applying the Settlement Agreement's proposed 10 percent return on equity
because Staff witness Kosnaski conceded it to be within his range of
reasonableness.  Further, the State Team contends its detailed analysis of
storm costs showed a normalized annual figure of $3 million rather than the
$1.4 million used by Mr. Naylor.  The State Team also questions Mr. Naylor's
view that PSNH's Administrative and General expenses are strictly a function
of capital investment as opposed to other additional expenses.

     The State Team further urges the Commission to endorse the Settling
Parties' decision not to unbundle transmission and distribution prices
despite the request of Freedom Partners.  The State Team points to FERC Order
888-A, concluding that it is unnecessary to unbundle transmission and
distribution functions, and FERC's refusal in Order 888 to adopt a bright-
line test for designating deliveries at certain voltages to be transmission
rather than distribution.  The State Team further points to FERC's
determination in Order 888 that states have authority over the delivery of
electricity to end-users and thus the authority to assess distribution
charges to all customers.  Further, the State Team agrees with PSNH that it
would be impractical to unbundle transmission and distribution charges at
this time because (1) the Commission has not yet approved PSNH's proposed
classification of transmission and distribution assets and (2) the
appropriate data is not yet available.  The State Team disputes Freedom
Partners' contention that PSNH may be disinclined to unbundle transmission
and distribution for fear of losing revenue. According to the State Team,
PSNH's recoverable costs would be fixed in any event and the only issue is
how to apportion them among customer classes.

Rate Design

     The State Team stresses that it is committed only to those rate design
issues contained in the Settlement Agreement, as distinct from those proposed
by PSNH.  The State Team concedes that PSNH's proposal satisfies the criteria
of the Settlement Agreement, but the State Team takes no position on the
proposed rates beyond suggesting that the question of future cost allocations
is best left to future Commissions.  The State Team points out that one of
its members, Director Deborah Schachter of the Governor's Office of Energy
and Community Services, testified in opposition to the new fees and charges
proposed by PSNH for retail customers during the IDCP.  The State Team also
notes that no party objected at the hearing when Ms. Schachter suggested
deferring the issue of whether to eliminate the Elderly Discount to another,
later proceeding.

Securitization

     The State Team describes securitization as both a "pivotal" part of the
Settlement Agreement and only a "distant pipe dream" if it were sought
outside the Settlement Agreement. The Settling Team reminds the Commission
that it is under a legislative mandate to determine whether the
securitization proposed here "will result in benefits to customers that are
substantially consistent with the principles contained in RSA 374-F:3 and RSA
369-A:1, X and with RSA 369-A:1, XI and the extent to which any RRBs issued
pursuant to the securitization proposal would be successfully traded at
favorable rates on the existing securitization market."  House Bill 464, Laws
of 1999, ch. 289.  The Settling Team answers those queries in the
affirmative.

     According to the State Team, the testimony of State Treasurer Georgie
Thomas and others establish that the securitization proposal is substantially
similar to securitization plans that have succeeded elsewhere.  Further, the
State Team points to the testimony of Mr. Kosnaski that securitization
continues to be financially advantageous up to a break-even interest level of
13.53 percent.  The State Team concedes that PSNH originally overstated the
value of securitization for benchmarking purposes, contending that it
accounted for 8.2 percentage points of the Settlement Agreement's 18.3
percent rate reduction.  According to the State Team, its witness John
Antonuk more accurately calculated that securitization would be responsible
for between 4 and 5 percentage points.

Northeast Utilities/Consolidated Edison Merger

     The State Team views the proposed merger of NU and Consolidated Edison,
and its relationship to this docket, differently than PSNH.  At the outset,
the State Team stressed that the Settlement Agreement contains a "clawback"
provision that would require PSNH's owner to share any acquisition premium it
reaped should PSNH's assets be sold within five years of Competition Day. (FN
20)  According to the State Team, this clawback provision "still has teeth"
because (1) the proposed NU/Consolidated Edison merger could fail, and (2) NU
and/or Consolidated Edison could still decide to sell PSNH's assets in a
manner that triggers the clawback provision.

     Where the State Team differs significantly from PSNH is in its view of
the "public interest" standard that the Settlement Agreement specifies would
apply to Commission review of any sale of NU itself.  According to the State
Team, this agreed-upon standard is more broad than the "no net harm" test
usually applied by the Commission in merger reviews.  In the State Team's
view, "no net harm" means the transaction must be, at worst, ratepayer-
neutral, whereas the public interest standard is traditionally applied to
protect ratepayers against high or discriminatory prices, unreliable service,
and is concerned with just and reasonable rates and service as well as a
balancing of utility and ratepayer interests.  However, the State Team urges
the Commission to defer resolution of this issue to the merger docket itself.

     Another difference between the State Team and PSNH relates to merger-
related savings. The State Team contends that such savings can be passed
through to PSNH customers as they occur, notwithstanding the fixed Delivery
Charge during the IDCP.  However, the State Team contends this is also an
issue properly resolved in the merger docket.  The State Team disagrees with
the recommendation of Mr. LaCapra, a witness for the Staff Advocates, that
approval of the Settlement Agreement be conditioned on the adoption of a
specific formula for sharing the acquisition premium arising out of the
NU/ConEd merger.  In the view of the State Team, there is no record support
for such a proposal.

Divestiture and Auction

     The State Team supports PSNH's offer to accept a Commission ruling that
conditions approval of the Settlement Agreement on NU affiliates not bidding
on PSNH fossil or hydro generation assets.  According to the State Team, such
a determination would obviate the need for an independent party to conduct
the sales, assuming that ConEd affiliates would also be excluded from bidding
in the event the ConEd/NU merger is consummated.  The State Team further
contends that, with NU affiliates excluded from bidding, the Commission
should permit J.P. Morgan to continue to manage the auction, thereby
satisfying the need for an independent party to play this role.  Further, the
State Team takes the position that permitting bidders to link offers to buy
generation assets with offers to sell energy for Transition Service would
"optimize the number of options available" and thereby maximize overall value
to ratepayers.

     The State Team agrees with PSNH that, in order to encourage municipal
participation in the hydro assets sale process, it is appropriate to delay
the sale of the hydro assets for 6-12 months after the auction of the fossil
assets.  The State Team further recommends that the Commission permit
municipalities to bid on individual hydro assets.  The State Team
acknowledges that running 2 auctions will increase administrative costs and
potentially cause problems coordinating river flows from the hydro plants as
they effect the fossil fueled plants' use of water.  This latter concern,
they say, can be addressed thru purchase and sales agreements. The State Team
also notes that a delay in selling the hydro assets will require the
Commission to decide how to use the hydro asset output until the sales are
complete.  While they offer 3 options, they note a preference that the
Company direct PSNH to use the output to supply a portion of Transition
Service.  See State Team Brief at 41.

     With regard to Seabrook, the State Team strongly disagrees with the
suggestion of Staff Advocate McCluskey that the Settlement Agreement should
be modified to allow for the longterm retention of PSNH's Seabrook interest.
The State Team questions Mr. McCluskey's assumptions, most notably the 14
percent discount he applies to account for the relevant risks. According to
the State Team, Mr. McCluskey fails to account adequately for the risk to
PSNH customers arising out of Seabrook remaining a part of regulated rates.
And, like PSNH, the State Team draws the Commission's attention to comparable
sale prices that these parties believe indicate that the Settlement Agreement
values Seabrook more favorably than the market does.  In the view of the
State Team, the Settlement Agreement provides for a prudent delay in the
Seabrook divestiture to permit the market for nuclear plants to mature,
followed by adequate safeguards in the form of a provision allowing the
Commission to establish a minimum bid for the asset.

Environment and Energy Efficiency

     The State Team urges the Commission to reject the suggestion of new
emissions limits for PSNH's fossil plants as a condition of approving the
Settlement Agreement.  They believe such requirements would impose new
stranded costs.  According to the State Team, the parties advancing the
notion of new emissions limits failed to produce any evidence as to the cost
of such initiatives.  The State Team asks the Commission to leave the
evaluation and implementation of air emission standards to the Department of
Environmental Services.

     With regard to Energy Efficiency initiatives, the State Team contends it
is not necessary for the Commission to make any long-term determinations in
this proceeding.  Rather, the Commission should endorse the Energy Efficiency
provisions of the Settlement Agreement because they allow for an interim
commitment to such initiatives pending the Commission's consideration of the
recommendations of the Energy Efficiency Working Group.  The State Team
disagrees with any suggestion that Energy Efficiency program decisions should
be made based on the programs' possible effect on stranded costs or other
fixed expenses.

Benchmarking

     According to the State Team, even assuming victory in the federal
lawsuit, an end cannot come to that litigation soon enough to afford
customers prompt rate relief and the advent of retail competition.
Additionally, the State Team points out that the end of the federal
litigation, whatever its outcome, would likely mark only the beginning of
efforts to restructure PSNH - a process that would again place before the
Commission the question of what represents a fair, equitable and balanced
resolution of issues associated with restructuring.  The State Team draws the
Commission's attention to the testimony of its witness, Mr. Little, who
estimated that, even assuming a high probability of success at each stage of
the federal litigation, the overall probability of success is well below 50
percent.

     In comparing its benchmarking analysis with that of Non-Settling Staff's
Mr. Naylor, the State Team contends that several adjustments are necessary.
The State Team notes that, in response to Mr. Naylor's analysis, it increased
its estimate of a likely rate reduction under traditional ratemaking,
exclusive of FPPAC and calculated against PSNH's base rates, to 3.35 percent.
Applying Mr. Naylor's analysis to base rates yields predicted reductions of
between 7.78 and 10.41 percent, according to the State Team.

     According to the State Team, further adjustments are necessary - but,
even before making them, Mr. Naylor's predicted rate reductions would be
insufficient to offset what the State Team characterizes as "a looming rate
increase that will be avoided by the Settlement, but that is inescapable
under a continuation of ratemaking in the traditional context."  This is
because the State Team predicts increases in FPPAC rates of 15 percent to
account for FPPAC's current failure to cover PSNH's current fuel and
purchased power costs, the loss of capacity transfer and joint dispatch
savings revenue, restructuring in the NHEC service territory and the end of
Hydro Quebec energy deliveries.

     Two additional adjustments to Mr. Naylor's benchmarking that were
recommended for comparison purposes by the State Team are as follows:
subtracting 2.86 percent to account for his failure to cover SBC costs;
removing Mr. Naylor's adjustment for changes in amortization methods (because
the State Team's benchmarking figure treats this issue elsewhere under the
State Team's methodology).  The latter adjustment reduces Mr. Naylor's
figures by 1.11 percent, bringing his range to 3.81 to 6.44 percent as
compared to the State Team's figure of 3.35 percent.

     Next, the State Team identifies five areas of Mr. Naylor's analysis that
it believes would not prevail in an actual rate case: his weather
normalization adjustment, his adjustments for nontest-year expenses, his
estimate of cash working capital requirements, his adoption of certain
conclusions reached by Staff  witness Cunningham on the issue of
depreciation, and his nonallowance of a return on PSNH's note to ISO-New
England.  According to the State Team, these adjustments reduce Mr. Naylor's
range to a range of 2.74 percent to 4.56 percent.  In summary, the State Team
contends that Mr. Naylor's analysis would not produce rate case savings that
are materially different from those developed by the State Team.

     The State Team further addresses certain benchmarking recommendations of
Mr. Traum of the OCA.  As already noted, the State Team emphatically
disagrees with OCA's contention that PSNH has committed a sanctionable breach
of the Rate Agreement.  Secondly, the State Team contests Mr. Traum's
assertion that PSNH has failed to compensate PSNH's ratepayers for
the sale of spare parts from Seabrook.  According to the State Team, Mr.
Traum's position on Seabrook spare parts "conflates the regulatory concept of
prudence with the notion of breach of contract."  The State Team's view is
that, even assuming the sale was imprudent, this does not translate into a
Rate Agreement breach for which PSNH would be liable.  Finally, the State
Team disagrees with Mr. Traum that the Commission should impute to PSNH the
lost revenues resulting from discounts offered to Special Contract customers.

     The State Team emphatically objects to the argument that in a
traditional rate case certain of PSNH's generation and regulatory assets
would be disallowed for recovery because they are not "used and useful."
According to the State Team, most of the published cases applying this
framework do so in the context of not allowing a regulated utility to add new
capacity, as opposed to disallowing recovery on and of existing assets.  The
State Team attacks the "used and useful" argument as "heads I win, tails you
lose" logic, contending that its proponents would restrict assets with below-
market costs to a capped rate of return while allowing above-market assets
either no return or a minimal one.  See State Team Brief at 59.   Finally,
the State Team maintains that the Commission would have to increase PSNH's
return on equity, adding a risk premium, to account for possible
disallowances based on the used-and-useful test.

     With regard to costs associated with retired nuclear units such as Maine
Yankee and Connecticut Yankee, and the extent to which these costs are
reflected in wholesale power transactions ultimately paid for by PSNH
ratepayers, the State Team takes the position that this is a matter solely
for resolution by the Federal Energy Regulatory Commission.  According to the
State Team, when the Settlement Agreement permits "unrecovered obligations"
from the retired plants to be included in stranded costs, the referenced
obligations are those established by FERC.

     On the subject of Hydro Quebec transmission support payments, the State
Team contends it is reasonable to include these sums as "generation-related
commitments" that may be recovered in a stranded cost charge.  According to
the State Team, the FERC considers them to be generation-related and the
Connecticut DPUC, while deciding not to include them as generationrelated
stranded costs, did recognize their "integral connection to securing energy."
Further, the State Team contends that even if the Commission deemed the
transmission support payments to be transmission costs, they could still be
included in the SCRC, particularly if the Commission makes clear it is doing
so to avoid the need to create a separate rate element.  The State Team
concedes that, in theory, these costs could also have been included in the
Delivery Charge.

     The State Team defends the Settlement Agreement's treatment of the loss
to PSNH of revenue from its former requirements contract with NHEC.
According to the State Team, even if PSNH had not reached a settlement with
NHEC terminating the requirements contract, NHEC would likely have received
offers from Qualifying Facilities to supply capacity at prices equal to those
charged by PSNH.  In these circumstances, according to the State Team, NHEC
would have been obligated to purchase the offered capacity, further eroding
revenue to PSNH.  In these circumstances, the State Team contends, the
Settlement Agreement appropriately divides between PSNH owners and
shareholders the estimated $13 million loss to PSNH from the termination of
the NHEC contract.

Other Issues

     The State Team does not agree with the view of Mr. Rubens, described
infra, that the Settlement Agreement raises the specter of a "death spiral"
in which new technologies will make it economically and technologically
possible for more and more PSNH customers to defect from the grid.  According
to the State Team, the period of alleged risk is relatively short, i.e., the
period of Part 3 stranded cost recovery, following which any such phenomenon
would require a national solution since all transmissions and distribution
companies would be effected.  The State Team believes the technology is not
sufficiently developed to pose any near-term risks of customer-base erosion,
and further points to Mr. Kosnaski's testimony to the effect that nothing in
the securities market suggests that investors perceive any such risk.

     The State Team urges the Commission to reject OCA's recommendation to
reserve the option to reject a high bidder for generation assets if that
bidder would again the ability to exercise market power as a result.
According to the State Team, this would increase stranded costs and do
nothing to protect against the potential exercise of market power.  Further,
the State Team contends that such a determination would violate the statutory
prescription for all reasonable steps in mitigating stranded costs.

     On the subject of nuclear decommissioning costs, the State Team takes
the position that the relevant provisions of the Settlement Agreement are
consistent with the applicable statute, RSA 162-F.  The State Team notes
that, at present, NAEC makes the requisite owners' payments into the nuclear
decommissioning fund, PSNH reimburses NAEC and the expense is charged to
ratepayers.  According to the State Team, the Settlement Agreement calls for
the buyer of Seabrook essentially to step into NAEC's shoes, subject only to
the risk that the Nuclear Decommissioning Finance Committee would increase
the charges.  The Settlement Agreement also allows the converse, i.e., a
windfall to the buyer arising out of a decrease in decommissioning charges.
In the view of the State Team, such a windfall possibility is not a violation
of RSA 162-F but merely a condition of the sale designed to maximize asset
value and minimize stranded costs.

     The State Team urges the Commission to reject the proposal of Great Bay
Power Company, described infra, to require PSNH ratepayers to pay for Great
Bay's decommissioning costs as a Seabrook Joint Owner.  According to the
State Team, when Great Bay purchased its Seabrook interest it did so knowing
it was assuming the risk of unrecoverable decommissioning liability.  The
State Team dismisses Great Bay's request as an effort to pass decommissioning
costs on to PSNH customers and force them to subsidize its future operations.

     Finally, on the subject of assistance to low-income customers, the State
Team contends that the relevant provisions of the Settlement Agreement are
consistent with RSA 374-F:3,V(a), which mandates the inclusion as part of
restructuring of "programs and mechanisms that enable residential customers
with low income to manage and afford essential electricity requirements."

B.   Public Service Company of New Hampshire

     In urging the Commission to approve the Settlement Agreement, PSNH
contends that the proposal constitutes an "equitable, appropriate and
balanced" approach to restructuring the Company, as that phrase is used in
the Restructuring Act.  See RSA 374-F:3, XII.  PSNH acknowledges that many of
the parties participating in this proceeding have offered various suggestions
that relate to their respective area of interest, but PSNH characterizes
those suggestions, when collectively assembled, as "the proverbial camel, not
the horse that was intended."  According to PSNH, the Settlement Agreement
meets each of the policy principles set forth in the Restructuring Act.

Recovery of Stranded Costs

     In PSNH's, view the overall average level of the SCRC of $0.0379 per kWh
represents the appropriate balancing of stranded cost recovery with near-term
rate relief.  According to PSNH, its financial forecast suggests that with
the SCRC set at this level, the Recovery End Date will occur some time prior
to the middle of 2007, at which time the Company's delivery rates will
decrease by 21 percent with additional decreases thereafter as IPP
obligations terminate.

     PSNH contends that reducing the SCRC and increasing the Transition
Service charge, as suggested by OCA, would trigger more than $600 million in
cost deferrals by the end of 2006. According to PSNH, such a plan would not
allow it to recover its ongoing expenses during the IDCP.  With regard to the
proposal of the BIA, described above, PSNH's position is that the plan
produces no additional value for customers and would only decrease the SCRC
by $0.001 per kWh while extending the Recovery End Date.

Transition Service and Rates

     In support of the proposed retail prices for Transition Service during
the IDCP, PSNH points out that the deregulated energy market in New England
is still in its "infancy," with 7,300 MW of capacity either under
construction or added to the system in 1999.  According to PSNH, as this
market matures and develops and as new capacity is added, there will be less
volatility during peak periods.  PSNH further contends that the proposed
Transition Service prices are consistent with analogous prices offered in
other nearby jurisdictions.

     Nevertheless, PSNH has indicated a willingness to accept a 3 mil
increase to the proposed per kWh Transition Services prices to $0.040 in the
first year, $0.041 in the second and $0.042 in the third.  PSNH also
indicates support for the concept of supplying Transition Service from its
existing generation resources, prior to their divestiture.  According to
PSNH, this would benefit customers by permitting them to keep the difference
between the price that the output would obtain in the wholesale market and
the cost of obtaining Transition Service from the same market. Further,
according to PSNH, such a plan would simplify the path to Competition Day by
eliminating the need to complete the process of acquiring Transition Service
beforehand, and it would also facilitate linked bids, i.e., proposals to
provide Transition Service while also purchasing PSNH generation assets.

     PSNH emphatically opposes retail adders for Transition Service as a
means of stimulating competition in the retail electricity market.  According
to PSNH, such an initiative benefits suppliers rather than customers, by
permitting the suppliers to hedge their risk and eschew economic
efficiencies.  Further, PSNH contends that retail adders would
disproportionately affect those who can least afford them, i.e., low income
customers.

Transmission and Distribution Service and Rates

     According to PSNH, the record contains sufficient evidence from which
the Commission can and should determine that the proposed average delivery
service charge of $0.028 per kWh is appropriate.  PSNH contends it will
sustain a revenue shortfall of $7.5 million - $10 million during the IDCP.
PSNH challenges the testimony of Non-Settling Staff witness Mr. Mark Naylor,
described in detail, infra, suggesting an average delivery service cost as
low as $0.026 per kWh. According to PSNH, Mr. Naylor applied a "mismatch"
when he used actual 1998 expenses and divided them by forecast sales for
2000.  Further, PSNH contends Mr. Naylor wrongly adjusted PSNH's
Administrative and General expenses by the ratio of delivery service plant to
total plant because the company's Administrative and General expenses will
not decrease in direct proportion to the divestiture of the generation
assets, which will not take place on Competition Day in any event.  Finally,
according to PSNH, the Company's actual delivery service revenue requirement
had increased to $0.0288 in 1998.  PSNH contends that these corrections would
revise Mr. Naylor's figure to greater than $0.03 per kWh for Delivery
Service.

Rate Design

     PSNH first notes that to maintain an average rate reduction of 18.3
percent, any increases to the Transition Service Charge, the SCRC or the
Delivery Charge would require offsetting decreases to one or both of the
other charges, because the energy consumption tax and the System Benefits
Charge are fixed.  As to the additional rate design issues raised by PSNH
outside the four corners of the Settlement Agreement, PSNH contends this is
an "opportune time" to make such changes given that some rate categories
would be eliminated and new charges would be collected pursuant to the
Settlement Agreement.  PSNH adds that the new charges it has proposed would
help make up the revenue gap it contends it must sustain under the Settlement
Agreement.

     PSNH urges the Commission to adopt its proposal to vary the SCRC by
class and thereby produce the same percentage rate decrease for residential
customers as all other customer classes when combined.  According to PSNH,
the alternate proposal advanced by OCA is based on the flawed assumption that
factors driving stranded costs - Seabrook, the Seabrook Acquisition Premium
and costs associated with IPPs - are all currently recovered on a uniform,
per kWh basis through FPPAC.  According to PSNH, most of these costs are
actually recovered through base rates, not through FPPAC.  Accordingly, PSNH
urges the Commission to reject OCA's suggestion of a uniform SCRC.  Further,
PSNH contends that OCA's plan would actually result in a lower SCRC for
residential customers than others, in violation of the Restructuring Act's
mandate for nondiscriminatory and fair stranded cost recovery.

     PSNH contends that its proposed charges for services provided to
competitive electricity suppliers are appropriate.  The Company draws the
Commission's attention to the testimony of
Mr. Morrison of the NHCUC that PSNH's proposed billing fee of $0.50 per
customer per month is the lowest price available for such services in the
area.

     In support of its proposal to eliminate the so-called "humped" rate
design that provides a discount for customers using 250 kWh per month or
less,  PSNH asserts that the humped rate has never been shown to promote
energy conversation.  In fact, PSNH draws the Commission's attention to the
testimony of Ms. Panori of the Save Our Homes Organization (SOHO) to the
effect that most customers do not understand the current rate design.
Accordingly, PSNH believes the Energy Assistance Program is a more
appropriate vehicle than the humped rate for addressing the needs of low-
income customers.

     PSNH proposes to eliminate the Elderly Discount Rate one year after
Competition Day. According to PSNH, this is appropriate because the original
justification for the rate - the unfairness of requiring elderly customers to
pay for utility construction projects from which they are unlikely to benefit
- - was removed when the Legislature enacted a statute prohibiting the
inclusion of construction work in progress (CWIP) in rate base.   PSNH notes
that the Elderly Discount rate was closed to new customers in 1982.

     PSNH proposes to implement a late payment fee for residential, general
and outdoor lighting services.  PSNH points out that while such charges are
authorized under the Commission's rules, PSNH is the only electric utility in
New Hampshire that does not presently charge all non-residential customers a
late payment fee.  In PSNH's view, absent such charges all customers bear the
costs imposed by customers who do not make their payments on time.

     PSNH proposes the imposition of a "field collection" charge, i.e., a fee
paid by customers who make payment on their accounts when a PSNH employee
arrives to disconnect their service. According to PSNH, there were more than
51,000 field collections in 1998 and the costs associated with this effort
are unfairly borne by all customers.

     With regard to its proposed increase in service charges and line
extension fees, PSNH points out that these charges have not been revised
since 1982 and 1979, respectively.  According to PSNH, the record supports a
determination that its proposed increases are in line with the cost of
providing these services.

Securitization

     PSNH characterizes the issue of securitization as non-controversial,
pointing out that OCA, Commission Staff witness Kosnaski, the Legislature as
well as the Settling Parties have all gone on record as supporting the notion
of securitization as an appropriate means of reducing costs to ratepayers.
In particular, PSNH draws the Commission's attention to House Bill 464,
Chapter 289 of the Session Laws of 1999, which specifically contemplates the
use of securitization (with Commission approval) in the context of a
settlement agreement relating to PSNH's stranded costs.  PSNH draws the
attention of the Commission to the testimony of OCA witness Ryan that the
desired Triple-A rating for the Rate Reduction Bonds will not be achievable
without a settlement to the pending litigation between PSNH and the
Commission.

Merger

     With regard to the proposed acquisition of NU by Consolidated Edison,
PSNH stresses that this docket is a "separate and independent proceeding"
from Docket No. DE 00-009, in which the Commission will decide whether to
approve the merger.  The Settlement Agreement specifically addresses a
possible sale of NU, providing that if PSNH's parent is sold within five
years of Competition Day, NU agrees that

notwithstanding any contrary provision of law, the merger, acquisition or
sale shall be subject to the jurisdiction of the Commission under RSA
Chapters 369, 374, 378 or relevant provisions, and that the merger,
acquisition or sale shall be approved only if it be shown to be in the public
interest.

SA, at 69:1967-1970.

     According to PSNH, the intent of this language and its reference to the
"public interest" was not to create a new and/or heightened standard for
Commission review of a sale of NU. Rather, according to PSNH, the intent was
to make clear that the Commission would indeed have jurisdiction over any
acquisition of NU: PSNH contends that the "public interest" standard
referenced in the Settlement Agreement is equivalent to the "no net harm"
standard the Commission has long applied to requests for approval of utility
mergers.

     Concerning the merger, PSNH also takes up the language in the Settlement
Agreement providing for adjustment of the Delivery Charge during the IDCP
to fully recover any changes in PSNH's costs that the PUC determines have
resulted from the imposition or modification of any tax, program, service, or
accounting change resulting from an order by any regulatory agency or by the
enactment of any law, or in the case of accounting changes, by the Financial
Accounting Standards Board ("FASB") or the Emerging Issues Task Force
("EITF").

SA, at 15:434-16:438.  According to PSNH, some parties have sought to advance
"strained interpretations" of this provision in order to argue that the
Delivery Charge could be modified to account for merger costs and savings
during the IDCP.  In PSNH's view, the intent of this language was to permit
changes solely for "costs mandated by force of law."

     PSNH indicates that it is willing to accept a Commission decision to
exclude NU subsidiaries from bidding on any of PSNH's generation assets when
they are offered for sale.  See Ph. II, Tr. Day XVIII, p. 221 (letter from
Berzak to D. Howland dated 2/24/00).  The Company also indicates its
willingness to abide by the Commission's determination on the overall conduct
of the divestiture process.  PSNH posits three alternatives: (1) Commission
assumption of management of the divestiture process, with NU subsidiaries
permitted to bid; (2) PSNH management of the divestiture process, with
Commission oversight and no NU subsidiaries bidding; or (3) PSNH management
of the divestiture process with NU subsidiaries permitted to bid and
"heightened oversight" by the Commission including an appropriate Code of
Conduct.  If the Commission opts for the first alternative, PSNH urges the
retention by the Commission of PSNH's current consultant, J.P. Morgan, given
that firm's detailed knowledge of PSNH's generation assets.  Ph. II, Tr.  Day
XVIII, pp. 213-215.

Divestiture and Auction

     PSNH states that it has received no "reasonable offers" from
municipalities.  Although PSNH asserts that it continues to believe the
provisions of the Settlement Agreement are sufficient to permit interested
municipalities to participate meaningfully in the bidding process, the
Company indicates a willingness to delay the divestiture of its hydro assets
"to allow an alternative pre-divestiture plan to be developed with the
cities' and towns' interests in mind."

Environment and Energy Efficiency

     PSNH does not agree with the CLF and the SAPL that the Commission should
require PSNH's existing fossil generation plants to meet new source
performance standards.  PSNH asserts that it has already made significant
progress in reducing air emissions "while other generators, or state
regulators outside of New Hampshire, have merely talked about reductions."
PSNH Brief p. 22, Section VIII.A.  PSNH objects to CLF witness Kinelly's
testimony that CLF's air emissions proposal in this docket is essentially
the same as was negotiated with Massachusetts generators.  According to PSNH,
unlike CLF's current proposal, the Massachusetts agreement included
"provisos, cost caps and triggering events from upwind generators" that
dampened the impact on those Massachusetts generators.  Brief, p23, Section
XVIII, A.  PSNH asserts that market forces, i.e., the existence of emissions
allowance markets, are the appropriate method for encouraging the mitigation
of environmental impacts.  According to PSNH, such market forces have already
led it to make decisions that will cause the nitrogen oxide (NOx) emissions
of its fossil plants to meet the standards proposed by PSNH.  However, PSNH
concedes that the same is not true for sulfur dioxide.

Benchmarking

     PSNH contends that the Settlement Agreement produces significantly
better results for its customers than they would receive through continuation
of the PSNH rate case.  In particular, PSNH contends that by adjusting the
calculations of Non-Settling Staff witness Naylor to reflect an "apples to
apples" comparison with the Settlement Agreement, the relevant comparison is
an 18.3 percent rate reduction under the Settlement Agreement versus a 7.55
percent rate case reduction.  Further, PSNH argues Mr. Naylor incorrectly
calculated the maximum percentage rate decrease under the rate case.  PSNH
believes Mr. Naylor's figure of 10.07 percent should be revised downward to
3.49 percent.

     PSNH criticizes Mr. Naylor's analysis for failing to account for the
impact of increased public policy expenditures due to the proposed SBC.  In
PSNH's view, this error requires a decrease in Mr. Naylor's rate reduction
range of 1.62 percent.  PSNH also criticizes Mr. Naylor's weather
normalization adjustment to increase test year revenues by $7.4 million.
According to PSNH, the Commission has never employed weather normalization
adjustments in setting rates for electric utilities.  PSNH objects to Mr.
Naylor's pro forma adjustment to PSNH revenues to decrease its demonstration
and selling expense by $2.7 million.  Although PSNH concedes that such
expenses decreased by that amount in the 12 months following the test year
ending September 30, 1998, PSNH pointed out that its overall customer service
expense actually increased by $2.2 million during the period.  PSNH also
contends that Mr. Naylor should have included PSNH's prepayment to ISO-New
England in his working capital allowance, and should have included costs
associated with reserves for major storms in his analysis of PSNH's expenses.
According to PSNH, Mr. Naylor should also have included restructuring
expenses in his benchmarking analysis as well as increases in non-fuel
Operations and Maintenance expenses. Finally, PSNH contends that Mr. Naylor
did not account in his analysis for the fact that the Settlement Agreement
provides for a more rapid, 12-year recovery of Seabrook expenses and thus
lower costs in later years than in a traditional ratemaking scenario.

     PSNH stresses that any benchmarking analysis must take account of the
underrecovery in its FPPAC account.  The deferred FPPAC balance is expected
to reach $103 million by May 31, 2000; customers would be responsible for
this sum in a traditional rate case.

     According to PSNH, Mr. Naylor's range of potential refunds under a
traditional rate case, $135 million to $171 million, must be offset both by
the FPPAC deferral and the adjustments to Mr. Naylor's benchmarking analysis
discussed, supra.  Relying on the testimony of its witness Mr. Mahoney, PSNH
estimated the likely refund to customers resulting from a traditional rate
case would be in the range of $0 to $8 million.  Further, PSNH contends that
implementing Mr. Naylor's refunds would cause the Company's return on equity
to drop below the approved level of 11 percent.  This, according to PSNH,
would run afoul of the Commission's legal responsibility to allow PSNH's
owner to earn a fair return on its investment.

     PSNH disagrees with the testimony of OCA witness Traum that the
Commission should impute $12.1 million in lost revenue from special contract
customers when conducting its benchmarking analysis.  According to PSNH,
special contract customers represent revenue gained rather than revenue lost
because such customers would not exist absent reduced prices.

     In its benchmarking discussion, PSNH addresses the likelihood of
ratepayers reaping additional benefits from resumption of the stayed "best
efforts" docket, No. DR 96-148, an inquiry into whether PSNH used its best
efforts to renegotiate contracts with 13 independent small power producers
(SPPs) as required by the Rate Agreement.  PSNH points out that the
Commission approved renegotiated contracts with five of the SPPs, all hydro
facilities, as well as two wood-fired plants, in 1994.  As to the remaining 6
SPPs, PSNH notes that it participated in a mediation process with the
assistance of the Attorney General's office and submitted the resulting
agreement to the Commission for approval, only to see the Commission reject
five of the six and issue what PSNH characterizes as an "unenforceable order"
as to the sixth.  According to PSNH, the Legislature recommended approval of
all six agreements, the Commission has not acted and, in these circumstances,
further pursuit of the Best Efforts docket is not warranted.

     PSNH contends there is also no basis for continuing to pursue the so-
called Light Loading docket, No. DR 96-149, which concerns obligations to
purchase power from certain IPP's during so-called "light loading" periods.
According to PSNH, Mr. Cannata of the Settling Staff, the Commission's main
proponent of this investigation, has testified here that there are no savings
available from the light loading and it should be disregarded for
benchmarking purposes.

     PSNH notes that the Settlement Agreement offers both quantitative and
qualitative benefits.  PSNH emphasizes that a failure to adopt the Settlement
Agreement would likely prolong the controversies at issue here for several
more years and thus unnecessarily delay the advent of deregulation in PSNH's
service territory.

Rate Agreement as Contract

     PSNH notes that it has not sponsored any witnesses in support of its
contention that the Rate Agreement binds its signatories, including the State
of New Hampshire, in contract.  As PSNH notes, that is an issue pending in
the federal litigation.  PSNH does not believe the Commission needs to
resolve the issue here, but does contest the testimony of OCA witness Judd,
described below, to the effect that the Rate Agreement is not contractual.
PSNH characterizes Mr. Judd's assertions as "dubious" and contends that on
cross-examination of Mr. Judd it became clear that the State of New Hampshire
"made judicial assertions concerning the existence of the regulatory
compact/regulatory contract between the State and PSNH."  PSNH claims
crossexamination also established that the Rate Agreement called for passage
of legislation binding the State in contract and that RSA 362-C met this
objective.  Accordingly, PSNH contends that continued litigation as to the
contractual nature of the Rate Agreement is "a matter of high risk to the
State."

     A related issue is whether PSNH breached the Sharing Agreement, a part
of the Rate Agreement that calls for sharing of energy and capacity between
PSNH and the NU initial system. According to PSNH, recently mandated
restructuring in Connecticut and Massachusetts caused CL&P and WMECO to cease
providing retail electricity thus, their energy and capacity requirements to
meet customer needs are zero and there are no longer any revenues from
capacity transfers, or joint dispatch savings.  PSNH references the
Commission's Brief in FERC Docket EL 96-53, regarding the Amended Partial
Requirements Agreement (APRA) between PSNH and the New Hampshire Electric
Cooperative (NHEC) where the Commission argued that industry restructuring
would not result in a breach of a requirements contract but would merely
drive requirements under such an agreement down to zero.  PSNH Brief at 39
X.C..  PSNH suggests that, in these circumstances, for the Commission to
conclude that there has been a breach of the Sharing Agreement would be
inconsistent.

Great Bay Power Corp.

     PSNH characterizes as "absurd" the contention of Great Bay Power
Company, described infra, that PSNH customers should be held liable for Great
Bay's share of Seabrook decommissioning costs.  PSNH notes that Little Bay
Power Company, an affiliate of Great Bay, recently purchased a 2.9 percent
interest in Seabrook and that Great Bay did not insist that Little Bay (whose
own decommissioning liability was funded by the seller of the interest)
assist Great Bay with decommissioning expenses.

Return on Equity

     For purposes of the Settlement Agreement, PSNH asserts that only two
figures for  equity returns are relevant: NAEC's return on equity on the
Seabrook Power Contract and the 8 percent return on equity embedded in the
stipulated rate of return (ROR).

     PSNH notes that there is no dispute that the Seabrook return on equity
should be seven percent as of Competition Day.  Where PSNH and the other
Settling Parties differ from others is in the contention that, in the event
NAEC retains the Seabrook asset, the return on equity should rise to 11
percent.

     PSNH disagrees with Staff  witness Kosnaski, who testified that 7.45
percent, based on adding 75 basis points as a risk premium to the Treasury
bond rate, represents an appropriate return on equity to use in the
Stipulated Rate of Return.  As support for its argument, PSNH notes a recent
Commission decision (Order No. 23,041, 10/07/98, DR 98-012) in connection
with the Granite State Electric Company restructuring settlement in which a
100 basis point (1.0 %) premium was added to the Treasury bond rate to
determine the appropriate return on equity. Further, PSNH contends that Mr.
Kosnaski failed to take into account PSNH's risk of not recovering all Part 3
stranded costs.

     According to PSNH, it is not necessary for the Commission to determine
the appropriate return on equity associated with the Company's transmission
and distribution assets.  In their view, the Settlement Agreement does not
rely on any particular return on equity determination, a determination only
necessary for benchmarking purposes.  PSNH urges the Commission simply to
disregard the testimony in the record expressing various expert opinions
about the appropriate return.

Millstone 3

     PSNH asks the Commission to approve a change in the Settlement Agreement
relative to PSNH's treatment of its interest in the Millstone 3 nuclear power
plant in Connecticut.  The Settlement Agreement calls for PSNH to transfer
this interest to an affiliate on or before Competition Day.  PSNH now
proposes retaining ownership until its ultimate divestiture. According to
PSNH, in these circumstances it would treat the Millstone interest as a
separate below-the-line item so as to maintain the financial bargain reached
in the Settlement Agreement.

Loan Fund

     PSNH strongly objects to the suggestion by some parties that some
portion of the securitization proceeds be set aside as a loan fund for the
benefit of competitive electricity suppliers.  According to PSNH, this would
amount to the creation of another public policy cost to be imposed on PSNH
ratepayers who are already responsible for mandated IPP purchases and system
benefits charges.  In PSNH's view, any such loan fund should be created by
the Legislature and funded by all New Hampshire citizens, not just PSNH
ratepayers.  Further, PSNH contends that the creation of such a loan fund out
of securitization proceeds would cause the Recovery End Date to be extended
and would likely require the approval of the federal SEC.

Seabrook Divestiture

     PSNH opposes Staff Advocate McCluskey's recommendation that the
Commission order PSNH not to sell its Seabrook interest on the schedule
contemplated by the Settlement Agreement.  According to PSNH, such a change
would increase the operational risks to NU and PSNH significantly.  Further,
PSNH cautions that after restructuring it would not be financially able to
withstand any significant Seabrook-related disallowances without suffering
"severe financial consequences."  PSNH also contends that, after Competition
Day, prudence determinations related to Seabrook will be the province of the
FERC because the Rate Agreement, vesting jurisdiction in this Commission,
will terminate.

Transmission and Distribution

     According to PSNH, it is unnecessary to unbundle transmission and
distribution rates at this time as suggested by Freedom Partners.  PSNH
agrees with the plan to designate all plant at or below 34.5 kV as
distribution plant, but contends that it will take some time to make the
necessary accounting changes and, thus, the relevant data for unbundling is
not yet available.

VIII.   COMMISSION ANALYSIS

A.   AUTHORITY TO CONSIDER SETTLEMENT

     Although the Commission has general authority under RSA 541-A:31, V(a)
to resolve contested matters through consideration of settlement agreements,
the Legislature has also recognized that there is a need for the Commission
to "consider negotiated settlements to expedite restructuring, near term rate
relief for customers and customer choice." 1998 N.H. Laws, 191:1, II.  The
Legislature has vested the Commission with express authority to establish
stranded cost charges through an adjudicated settlement proceeding, see RSA
374-F:4, V, and to examine structured financing "in the context of settlement
agreements."  RSA 369-A:1, IV.  Moreover, the Legislature has required that
the Commission "hold hearings to review any proposal that includes
securitization that is part of ... a settlement proposal," 1999 N.H Laws
289:3, I, and has authorized the Commission to issue an order on such a
settlement proposal.  Id.  Lastly, the Legislature has stated that the
Commission "should retain jurisdiction over any proposed settlement."  RSA
369-A:1, X(j).  Thus, when read together, the foregoing statutes and session
laws make it clear that the Commission is authorized, if not strongly
encouraged, to consider the Settlement Agreement that is before us in this
docket.

     Additional support for the Commission's authority to resolve the various
outstanding restructuring and rate issues through consideration of settlement
is found in Appeal of Richards, 134 NH 148 (1991).  In that case, the New
Hampshire Supreme Court determined that the Commission was not required by
either statute or the federal Constitution to employ a traditional
ratemaking analysis when scrutinizing the so-called "Rate Agreement."  Most
significantly, the Court noted the well-established principle set out in
Federal Power Commission v. Hope Natural Gas Co., 320 U.S. 591 (1944), that
"the methodology used to set rates is irrelevant.  . . . Instead, it is the
result reached that is important: '[i]f the total effect of the rate order
cannot be said to be unjust or unreasonable, judicial inquiry is at an end.'"
Appeal of Richards, 134 NH at 164, quoting Hope, 320 U.S. at 602.  The Court
in Richards also stated that it did not "foreclose the possibility that there
existed other constitutionally permissible means of determining 'just and
reasonable' rates other than use of traditional ratemaking methodologies."
Id.  In light of the foregoing, an adjudicated settlement is such a
constitutionally permissible means of resolving the issues raised by the
Settlement Agreement.  Accordingly, we affirm our decision made at the outset
of this case that we were not required by RSA 374-F to proceed with the
interim stranded cost hearing or the base rate proceeding at the same time we
considered the instant Settlement Agreement.  See Order No. 23,299 (September
16, 1999) at 37.  We further conclude that we have the authority to resolve
all of the pending matters at issue in this docket in the context of an
adjudicated settlement.

B.   STANDARD OF REVIEW

     Although this docket involves the consideration of a negotiated
agreement, it is somewhat unusual in that the Settlement Agreement is opposed
by some parties and only conditionally supported by others.  Nonetheless,
even if all the potentially interested parties had joined the Settlement
Agreement, we could not approve it without independently determining that the
Agreement comports with the applicable standards.  As the present case
involves the determination of several different dockets, some falling within
the purview of the Electric Utility Restructuring Act, RSA 374-F, and some
under the category of "ordinary ratemaking," the Settlement Agreement must be
reviewed against more than one standard.  For example, the Settlement must
comport with the 15 interdependent principles set forth in RSA 374-F:3.  It
must also produce Transition Service charges "that accomplish the principle
of near term rate relief," 1998 N.H. Laws, 191:1, IV, and stranded cost
charges that are "equitable, appropriate, balanced and in the public
interest,"  RSA 374-F:4, V.  And although it must comply with a variety of
specific Legislative directives, the ultimate test is whether the Settlement
Agreement produces a result that is in the public interest, and an overall
rate that is "just and reasonable."  See 1999 N.H. Laws 289:4 and RSA 378:28.

     The Commission's findings with respect to whether the Settlement
Agreement is in the public interest must be supported by competent evidence
in the record. See Appeal of Stetson, 138 NH 293, 296 (1994).  The Settlement
Agreement in this case was debated in a litigated adversarial process in
which the Commission received a considerable amount of evidence.  The
Commission held 33 days of adversarial hearings in which dozens of witnesses
and experts testified and were cross-examined.  Over 300 exhibits were
introduced into evidence and dozens of letters from members of the public
were included in the record.  In addition to the adversarial sessions, the
Commission held seven evening hearings around the State to solicit comments
from the public.  The voluminous record developed as a result of the
aforementioned proceedings also includes the record of the individual dockets
subsumed within the Settlement Agreement, some of which has been incorporated
into this record by reference.

     The size of the record matters little, however, if it is not reviewed,
considered and ultimately judged according to standards that provide the
public with the assurance that a just and reasonable result has been reached.
As the Commission noted in the "Final Plan for Restructuring New Hampshire's
Electric Industry," issued in Docket No. 96-150 on February 28, 1997, at 3,
the fundamental responsibility that has guided the Commission is the
legislatively imposed requirement to act as the arbiter between the interests
of the customer and those of the utility. RSA 363:17-a.  The Restructuring
Act did not change this responsibility, and in fact it reemphasized it: "In
making its determinations, the commission shall balance the interests of
ratepayers and utilities during and after the restructuring process."  RSA
374-F:3, XII (a).  This most basic responsibility has been our guide in
deciding the issues presented in this docket.

C.   BENCHMARKING ANALYSIS

     In determining whether the Agreement presents a reasonable outcome for
the Restructuring Docket, the Rate Case, various FPPAC cases, and other
subsidiary dockets, we must be able to compare the Settlement Agreement to
the results that could be expected in the event those dockets were litigated.
It is not necessary to find that each particular adjustment or condition that
we might have imposed in a litigation of those individual dockets is present
in the Settlement Agreement.  Settlement provides an opportunity for creative
resolution of problems, and the benefits of such original thinking should not
be forsworn merely because they might not be contemplated under ordinary
processes.  Further, in the search for an outcome that is in the public
interest, and for rates that are just and reasonable, especially where the
basis for such an assessment includes a forecast of future events, one
outcome that cannot be achieved is absolute certainty.

     In order to ensure that the record before us would be sufficient to
decide the issues presented by the Settlement, at the Prehearing Conference
held in this Docket on August 10, 1999, we required that the Settling Parties
present "benchmark testimony:"  their analysis of the expected outcomes of
the various dockets that the Settlement Agreement purports to resolve.
Prehearing Conference, Tr. at 159:16-23.  The non-settling parties were also
given the opportunity to submit such testimony and exhibits.

     The benchmark testimony was needed to enable the Commission to compare
the expected rates and rate path under the Settlement with such rates and
rate path that may be achievable were the Settlement Agreement not
implemented and litigation of the pending dockets resumed.  In addition, the
Legislature suggested this comparative exercise in 1999 N.H. Laws, Chapter
289:4, which provides that:

[P]articipants should file in a settlement proceeding any testimony,
exhibits, data requests, and data responses relevant to the cited dockets in
order to provide a basis for the commission and legislature to compare the
settlement to other possible outcomes.

     The Commission has focused on a rate path that is conservative and
realistic in its assumptions, relying as much as possible upon well-
established precedent and traditional analysis. The Commission's benchmark
analysis cannot simply assume a value for every conceivable downward
adjustment in rates.  A responsible analysis must allow for the possible
failure of evidence to support a plausible theory, and for the risk of
external proceedings that could delay, supercede or overturn a Commission
ruling.  By the same token, the analysis included reasonable upward factors
proposed by the Company and Settling Parties.  Further, the Commission cannot
assume that future conditions will develop in a manner that the harshest
critics of the Settlement have posited.  In this way, the Commission's
benchmarking analysis not only reflects a just and reasonable result, but
safely accounts for unknown and unknowable future events.

     One thing that can be known for certain is that the future will be
different than what we expect.  Thus, the benchmark analysis is not designed
to predict future rate paths with certainty. Rather, it is designed to
provide a means to compare various models of the future operating under
similar real-world assumptions, and to indicate whether the benefits asserted
under the Settlement Agreement are as significant as claimed, when compared
with the other likely and plausible path of events.

     We also stress that the assumptions employed in the "Business As Usual"
model concerning the expected outcome of the various underlying dockets do
not represent the Commission's final determination on any of the issues in
those dockets, nor are they a prejudgment of the merits of those cases.  It
is the Commission's expectation that further proceedings would be required in
each of these dockets before a final decision could be made, if the
Settlement were not implemented and individual case litigation were to
resume.  Thus, it is entirely possible that the actual outcome in specific
cases could vary considerably from what we have assumed.  We have, however,
attempted to be as reasonable and realistic in our assumptions as possible.

1.   Settlement Agreement Rate Path

     Several rate paths were offered by the Settling Parties during the
course of the hearings, containing slight variations due to assumptions
regarding inflation, the cost of the Rate Reduction Bonds and the actual date
competition begins.  We have determined that the most reliable rate path
under the Settlement Agreement is found  in Phase I, Exhibit 86, which is a
recalculation of the financial model assuming that "Competition Day" occurs
on July 1, 2000.  This model takes into account the Rate Reduction Bonds at
an all-in cost of 7.25 percent and reflects the continued current
amortization of stranded costs due to the occurrence of Competition Day six
months later than assumed in the original model.

     For consistency in comparing the Settlement Agreement rate path to the
"Business As Usual" rate path scenarios, the Commission has made one
adjustment to the rate projections assumed in Phase I, Exhibit 86.  The model
as presented by the Settling Parties assumed that Transition Service is
provided for the initial three years at a per kWh cost of $0.037, $0.038, and
$0.039.  As discussed below, the Commission has determined that these prices
are too low and create a high risk that substantial deferrals would be
created.  The Commission has, therefore, assumed Transition Service prices
for this period of $0.040, $0.041 and $0.042 per kWh, respectively, thereby
increasing the Settlement Agreement rates for each of the first three years
by $0.003 per kWh.  The model's assumption that there are no Transition
Service deferrals is not changed, however, because we believe that the
increased prices will either eliminate or significantly reduce such
deferrals.

     During the hearings, the State Settling Team argued that the expected
rate path of the Settlement Agreement would provide benefits in excess of
$790 million over 12 years in comparison with Business As Usual.  See Ph.I,
Ex. 103 and 117.  The impact of the reduction in SCRC at the Recovery End
Date for Part 3 stranded costs was included within the $790 million estimate
of net benefits, while an additional decrease, to be realized in 2012 when
the Rate Reduction Bonds are fully amortized, was not.  See Ph. I, Tr. Day
XIII, at 64:7.

2.   "Business As Usual" Rate Path

     The Commission has determined to assume two "Business As Usual" rate
paths:  one with lower, more conservative assumptions concerning downward
adjustments to the Company's rates in the event we proceeded to complete the
base rate investigation (Docket No. DR 97-059), and a second scenario
assuming higher, less conservative adjustments concerning the outcome of that
docket.  All other assumptions in the two paths are the same.

a.   Docket DR 97-059:  Base Rate Reductions

     We have incorporated base rate decreases of 7.59 percent and 10.07
percent into our analysis, which are the low and recommended overall
reductions as presented by Non-Settling Staff witness Mark Naylor. (FN 21)
We believe that use of these levels of decreases for the benchmark analysis
is reasonable, even though several significant adjustments were challenged by
the Settling Parties, and certain additional adjustments were advanced by a
number of non-settling parties.

     Mr. Naylor, in arriving at the lower end of his range of base rate
decreases (and thus the upper end of his range of revenue requirement
estimates), assumed that only 50 percent of Staff's income statement
adjustments would be accepted by the Commission.  While there may be merit to
certain of the Settling Parties' criticisms of this analysis, their critique
is lacking in that they have not allowed for any offsetting upward adjustment
for those items that are accepted by the Commission.  Thus, the Commission
finds that Mr. Naylor's approach of estimating a range of outcomes after
applying a simple 50 percent reduction to the entire list of proposed income
statement adjustments provides a reasonable upper value to give to the base
rate proceeding for purposes of the benchmark analysis.

     An additional measure of its reasonableness is that the range of
reductions does not include any items from Mr. Naylor's list of "other
adjustments" (Naylor Direct, Ph. II, Ex. 132, at at19:5-8), although several
may be quite considerable.  For example, as OCA and City of Manchester also
argued, there may be good reason to require a significant adjustment to
PSNH's cost of equity and capital structure to account for the strength of
PSNH's equity-debt ratio and coverages on a "stand-alone" basis.  By not
including this and the "other adjustments" in our analysis, the range of base
rate decreases we have assumed remains reasonable in light of the Settling
Parties' critique.

     We also note that several of the Settling Parties' proposed adjustments
to Mr. Naylor's range are incorrect.  For example, the brief of the Settling
Staff and GOECS argues for removal of Mr. Naylor's adjustment for a changed
and improved method of amortizing regulatory assets. This removal is simply
illogical for benchmarking purposes, because the comparison is not to be made
between the State Team's base rate benchmark and Mr. Naylor's, but between
the rates that result from Mr. Naylor's adjustments and the rates that result
under the Settlement Agreement.

     We have not included any of the additional adjustments raised by OCA
witness Traum regarding base rates.  We stress that this is not a reflection
upon the ultimate merit of his proposals.  Rather, it is to maintain a
conservative approach to the benchmark analysis.  For example, the Commission
does not agree with PSNH's quick dismissal of Mr. Traum's testimony
concerning an adjustment for "lost revenue" from special contract customers.
A review of the special contract orders reveals that the Company was on
notice that the Commission was leaving open to a future determination the
issue of whether or to what extent it would allow recovery of the difference
between the special contract rate and the regular tariff rate.  Likewise, we
have not assumed any write-off of the Acquisition Premium, or reduction in
the associated carrying cost rate, as proposed by OCA.  While it is not clear
what merit there is to a 1 percent return on equity as proposed, in a
litigation of these issues weight would have to be given to the arguments of
OCA relating to the risk-free nature of this asset, for example.  However, we
have chosen not to reflect these considerations in our benchmarking analysis,
to maintain a conservative approach.

b.   Systems Benefits Charge Comparability

     As recommended by the Settling Parties, we have included an upward
adjustment to the Business As Usual model for the level of System Benefits
Charge to recognize that the Settlement Agreement provides these benefits,
and therefore we want to compare it to an outcome that also contains these
benefits.  However, while we have incorporated the costs at the same level
and during the same time frame they are incurred under the "Settlement
Agreement" scenario, it should be recognized that under "Business As Usual,"
a separate proceeding would have to be held before these amounts could be
included in rates, and therefore there would be some lag before this
adjustment would take effect.  In addition, our comparison takes into account
that there is already some amount of costs in current rates for these types
of programs.  Thus, assuming that current rates include $0.004 per kWh for
these programs, in the first year of Business As Usual, in both scenarios
(high and low base rate decrease assumptions), rates were adjusted upward by
$0.021 per kWh, in the second year by $0.026, and in the third year and
thereafter by $0.031.

c.   "Other Dockets" Adjustment

     The value of $34 million (representing a one-time decrease to rates) for
the other dockets ("Best Efforts," "Light-Loading," "Unit 2 Spare Parts,"
etc.) as discussed by Mr. Cannata beginning on page 115 of his direct
testimony is accepted for modeling purposes.  That value is
assumed to be flowed through over six months as a decrease to rates beginning
January 2001. Mr. Cannata's analysis provides a reasonable basis for modeling
the benchmark scenarios on these issues.

d.   FPPAC Undercollection Offset By Base Rate Reconciliation

     The FPPAC undercollection as of July, 2000 is assumed to be $101.4
million, and is included in both Business As Usual rate paths.  This entire
amount is offset by the $135 million reconciliation of the rate reduction to
the temporary rate period under the 7.59 percent base rate reduction
scenario, or the $171 million reconciliation under the 10.07 percent base
rate reduction scenario.  This results in a remainder of a one-time $33
million or $70 million decrease to base rates.

     PSNH, in its brief, challenged the potential reconciliation of any rate
case decrease to the temporary rate period.  The Company argues that during
the temporary rate period, with the rates that were in effect, its earnings
were almost precisely at its allowed level.  First, PSNH's brief overstates
its case: Mr. Mahoney only testified that the earnings for the first year of
the temporary rate period were at 11.2 percent.  Earnings for the second year
(year ending June 30, 1999) were 13.65 percent.  Second, and more to the
point, these "reported" earnings are not the basis for the Commission
determination of reasonableness.  Numerous adjustments to revenues and
expenses are required before the Commission will accept a particular result
as indicative of a utility's regulatory earnings.  The Company's claimed
levels may be the starting point of the analysis; they are not the end point
and do not determine whether and to what degree a retroactive adjustment of
the temporary rates is warranted.

e.   Projected FPPAC Increase

     In both Business As Usual scenarios, the FPPAC is assumed to increase by
approximately $70 million per year above the $0.00383 per kWh current FPPAC
rate, as a result of: 1) the loss of wholesale revenues on account of the
PSNH-NHEC settlement (assumed to be $24 million/year); 2) the continuation of
costs under the Hydro-Quebec contract (assumed to be $6 million/year); and 3)
loss of the joint dispatch/capacity transfer savings under the Sharing
Agreement and Capacity Transfer Agreements (assumed to be $40 million/year).
This annual FPPAC increase of $70 million beginning in June, 2000 is offset
in the model during the first twelve months by the amounts remaining from the
rate base decrease reconciliation and the $34 million decrease from the
"other dockets."

     While this analysis includes the increase to the FPPAC due to loss of
joint dispatch and capacity transfers under the Sharing Agreement and
Capacity Transfer Agreements, it has not included offsetting revenues to
FPPAC as a result of off-system sales by PSNH.  Because the Sharing Agreement
between PSNH and the NU system is no longer in operation, 100 percent of the
benefit of off-system sales made by PSNH out of its excess capacity and
energy would be available to offset FPPAC costs.  This would have a
moderating effect upon the FPPAC, and the specification of the benchmark
without an estimate for such revenues represents a further conservatism in
the analysis.

f.   Termination Of Seabrook Deferred Return

     Beginning in June, 2001, under Business As Usual the termination of the
amortization of the Seabrook Deferred Return would result in an annual
revenue requirement decrease of approximately $110 million.  This amount
would offset the FPPAC increase of $70 million, and allows for an annual $40
million rate decrease to base rates to be reflected in the Business As Usual
scenarios.

g.   Acquisition Premium, SPP "Step Adjustment" and T&D Rates

     In June 2002, deferrals from SPP costs start to drop off through the
FPPAC, beginning at approximately $5 million a year.  Both Business As Usual
scenarios incorporate a "stepadjustment" to allow the regular and automatic
flow-through to base rates of reductions in the amortization of the
Acquisition Premium and SPP deferral.  Both the high and low Business As
Usual scenarios also incorporate the same assumptions as the Settlement
Agreement concerning increases in SPP costs and Transmission and Distribution
charges.

h.   Seabrook Power Contract Rate Of Return

     The Commission's benchmark analysis does not include any potential
decrease to the return on equity included in the Seabrook power contract that
may be obtained through a proceeding at the FERC.  A strong argument could be
made before the FERC that the appropriate return to be applied to the
Seabrook power contract is a relatively risk-free rate, to reflect what has
been termed the "bomb-proof" nature of the contract.  It would appear that a
power purchase contract where the buyer's obligations to pay are "absolute
and unconditional and shall not be affected by any circumstances," (See
Section 6 (c) of the Unit Contract between PSNH and NAEC) is significantly
different from the terms and conditions of comparable arms-length power
purchase arrangements.  To the extent the Commission does not speculate as to
the likely outcome of such a FERC proceeding, the benchmark analysis is
conservative.

3.   Period Of Comparison

     In declaring its preference for a benchmarking analysis, the Legislature
did not direct any particular time period for comparing the Settlement
Agreement with "other possible outcomes." 1999 N.H. Laws 289:4.  The only
temporal directives from the Legislature of which we are aware are the
duration of Transition Service and "near term" rate relief.  See RSA 374-F:3,
V(b) and XI. Accordingly, in the absence of a Legislatively-imposed time
horizon for benchmarking purposes, we find it appropriate in our detailed
revenue requirements modeling to look out over a period that is long enough
to capture events that are certain, but short enough to avoid the difficulty
associated with predicting the long-term future.  For these reasons, we have
modeled the Business As Usual and Settlement Agreement rate paths through
2007.  We have assumed, based upon the testimony of Mr. McCluskey, that the
PSNH-owned system will have sufficient energy and capacity to serve its own
needs during this time, and therefore no additional costs are allocated to
the Business As Usual model to account for increases in supply.

     The Commission is aware that additional savings occur under the
Settlement Agreement shortly after 2007 due to the Recovery End Date for Part
3 stranded costs, and an additional decrease is realized in 2012 when the
Rate Reduction Bonds are fully amortized.  We have not
attempted to model specific additional decreases or moderating effects that
could occur under Business As Usual past 2007.

     It is also likely that the Seabrook Power Contract could be scrutinized
or otherwise refinanced if the Settlement Agreement is not implemented.  The
benefits to PSNH and NU of decreased risk and an immediate infusion of cash,
with the corresponding benefits to ratepayers in the form of lower rates,
could compel the parties to attempt to reach a compromise on this asset, even
if of a more limited scope that the current Settlement Agreement.  It is
difficult to predict when that would occur or what the precise level of
savings would be, though we believe that such savings may be significant.
(Under the Settlement Agreement, almost half of the proposed rate decrease is
due to savings realized through securitization.)  See Ph. I,  Ex. 49.  Thus,
for purposes of comparison to the Business As Usual model, the Commission has
determined to give less weight to the savings realized by the Settlement
Agreement after 2007, because of the likelihood that similar savings could be
realized under Business As Usual.

4.   Benchmarking Results

     A comparison between the rate paths of the Business As Usual and
settlement agreement models are shown below.

(Two Excel Flow Charts Attached)

     Under the assumptions described above, the Settlement Agreement produces
a net benefit as compared to Business As Usual of between $128.5 million
(assuming a base rate reduction of 7.59 percent) and $63.7 million (assuming
a base rate decrease of 10.07 percent). (FN 22)  The range of this difference
is significantly less than the $790 million in net benefits relative to
Business As Usual estimated by the State Team during the hearings.  See Ph.
I, Ex. 103 and 117.  Although the Commission's analysis reveals that the rate
decrease benefits achieved under the Settlement Agreement are greater than
those that are likely to be achieved under the Business As Usual scenarios,
this conclusion does not automatically warrant acceptance of the Settlement
Agreement.  We must apply the public interest standard to determine whether
the Settlement Agreement should be implemented.

D.   APPLICATION OF THE PUBLIC INTEREST STANDARD

     In determining whether the result is in the public interest, there is no
formulaic principle, such that a benchmarking result that shows a certain net
present value benefit (or lack thereof) automatically leads to a conclusion
of acceptance (or rejection).  The Commission must factor in the overall
effects of the Settlement Agreement as well.

     The Settlement Agreement achieves an agreement by PSNH to write off a
certain level of assets in exchange for the securitization and recovery of
remaining costs, including costs claimed by PSNH to be eligible for recovery.
In the end, the Company will effectively write off $225 million after tax
(and remain at some risk for further portions of its Part 3 costs, sales
price for Seabrook under $100 million, etc.).  When considering the extent to
which PSNH should recover its remaining costs, it is necessary to take into
account the fact of the write-off proposed in the Settlement Agreement.
Under the Settlement Agreement, ratepayers will shoulder approximately $1.9
billion to $2.3 billion of claimed stranded costs, depending upon the  market
price forecast employed.  As shown by the benchmarking analysis, the write-
off, coupled with the financing cost decrease from securitization, leads to a
potentially significant net present value reduction in revenue requirements
compared to conservative Business As Usual scenarios.

     These potential benefits of the Settlement Agreement are less than 25
percent of the promised rate benefits at the high end, and less than 10
percent of promised  rate benefits at the low end.  However, in addition to
the net present value revenue requirement benefits estimated under the
Commission's benchmarking analysis, other benefits would accompany the
implementation of the proposed Settlement.  Numerous dockets will be
resolved.  Litigation, which has created exceptional uncertainty as to future
rates, will end and competition will begin. The Settlement Agreement also
provides a functioning "risk-sharing" mechanism - as required by RSA 369-A:1,
X(e) - that may enable consumers to realize further reductions in stranded
cost recovery.  In addition, the Settlement Agreement contains a funding
mechanism for low-income and energy efficiency programs.  These benefits for
customers are real and must not be discounted.

     The benefits of the proposed Settlement to PSNH and NU, however, are
also significant, and do not require that the Company wait 12 years for them
to be fully realized, as do some of the promised consumer benefits.  PSNH is
relieved of its obligation to provide generation service, while it obtains
open access to retail markets throughout the state.  It too would enjoy the
end of the uncertainty caused by the current litigation, and the resolution
of more than a decade of difficult relations with its customers and the
State.  The Company would replace regulatory uncertainty with the securitized
financing of a large portion of its investment, a benefit correctly
characterized by the Legislature as "extraordinary."  RSA 369-A:1, X.
Securitization will decrease the Company's risk and provide it with a large
infusion of cash.  The Settlement would give PSNH and NU relief from the
restriction on PSNH's ability to pay dividends to its parent. PSNH's own
financial models reveal that the Company makes its way through this process
with fairly robust financial indicators.

     In addition, we would point out that we agree with Mr. Kosnaski's
assessment that because "PSNH's load growth forecasts understate both
underlying status quo load growth (i.e. that which would take place in the
absence of rate reductions) as well as dynamic (adjusted for demand responses
to rate reductions) load growth, the risk that PSNH will fail to recover any
of its Part 3 stranded costs is virtually nil." Ph. II, Ex. 143, at 27-28.
We think that load growth will work to PSNH's benefit.

     Most significantly, and as argued by Staff Advocates witness LaCapra,
the resolution of the stranded cost issue and the deregulation of the market
have attractively repositioned PSNH and NU such that companies like
Consolidated Edison seek to acquire them at a significant premium above
market value.  Even if the acquisition proposal at issue in Docket DE 00-009
is not realized, we believe that NU will continue to have many "opportunities
to use [its] existing assets to their maximum financial benefit." (FN 23)
Thus, the balance we must strike between the interests of ratepayers and the
Company must include in its calculus, to some extent, the new opportunities
created for the Company.

     It is also true that despite the benefits of the Settlement, rates will
remain above the regional average for a significant period, until the RRBs
are fully paid.  Ratepayers will also forego potentially greater rate
reductions as historic claims are subsumed under the Settlement. The
financial models accompanying the Settlement Agreement do not appear to
reflect all the adjustments agreed to by the Settling Parties, and
potentially overstate required revenues as a result.  In addition, the
Settlement Agreement as initially proposed contains certain provisions that
could have a chilling effect on the development of a workably competitive
wholesale energy market, to the ultimate detriment of New Hampshire
electricity consumers.  Further difficulties with the asset divestiture
provisions of the original Agreement were brought out during the hearings.

     We also think it is important to note that many parties to this docket
and many public officials are understandably reluctant to have the State
participate in any settlement that involves anything resembling long term
commitments or rate paths.  The experience of the State under the Rate
Agreement and the differences between what was anticipated to happen and what
actually did happen make people understandably wary of a new "agreement."
While we believe that this Settlement Agreement is quite different from the
Rate Agreement,  it is still important to keep this concern in mind when
weighing the benefits to ratepayers and to the Company that this Settlement
Agreement puts forth.

     Having examined the balance between the benefits and risks the Company
takes under this Settlement Agreement, and the benefits and burdens to the
ratepayers, the Commission finds that the Settlement Agreement as filed is
not in the public interest.  Accordingly, for the Agreement to fulfill the
statutory requirement that the stranded cost charge be "equitable,
appropriate, and balanced, [. . . ] in the public interest, and [. . .]
substantially consistent" with the Restructuring Act's interdependent policy
principles pursuant to RSA 374-F:4, V, a rebalancing of the equities in the
disposition of claimed stranded cost recovery is warranted, as a condition of
accepting the proposed Settlement Agreement.

E.   CHANGES REQUIRED TO ACHIEVE THE PUBLIC INTEREST

1.   Rebalancing The Risks And Benefits Of The Settlement Agreement

We need not reject the Settlement Agreement, as proposed by some parties, in
order to remedy the imbalanced results it produces.  As noted above, the
Settlement Agreement does promise numerous benefits, even if the anticipated
rate reductions are not as significant in comparison to Business As Usual as
estimated by its proponents.  Some of these would be difficult to achieve
without Settlement, and all of them are uncertain to one degree or another.
Adjusting stranded cost recovery to achieve financial balance in the
Settlement Agreement will, if accepted by the Settling Parties (and
particularly the Company), permit the Commission to bring this chapter in the
PSNH restructuring to a close, and lock in the benefits of the Settlement,
while augmenting their value to achieve the requisite balance.  In addition
to financial rebalancing, the Commission finds it necessary to address other
areas of the Settlement Agreement that may not directly impact rates, but
that have significant public policy implications.

     In considering the changes needed to bring the appropriate balance to
stranded cost recovery, we do not subject each line item to a narrow
interpretation of the definition of stranded costs as argued by the Staff
Advocates.  Our objective is to reach a result consistent with the statutory
standard when viewed overall.  The attempt to resolve the myriad of issues in
a "big picture" manner is appropriate, since settlements, through the give
and take of negotiation, seek to achieve the optimum resolution of the bigger
picture.  Each individual item may not be resolved in the manner most
beneficial to one side or the other; the real question is how the entire
result affects the parties.

     The Settling Parties followed a similar logic in designating assets to
be written off or claims to be compromised to achieve the desired end point.
From time to time the Settling Parties would note that their basis for a
particular provision in the Agreement was essentially the "give and take" of
negotiations.  It also appears that Settling Parties designated particular
assets or portions of assets to be written off in order to maximize the
beneficial effect of the write-off upon ratepayers, not to reflect some
agreement as to the merits of the Company's claim to recovery if each
specific claim were litigated.  For example, it made sense to write off the
Seabrook contract as opposed to the undepreciated cost of a fossil fuel
plant, because the NAEC contract is the longest-running and most costly asset
the Company owns.  PSNH continues to claim that it had an iron-clad claim to
100 percent recovery of these costs, although it is agreeing to this write-
off as part of the give and take of settlement.

     Although it has been suggested that the Commission resolve the legal
question of whether the Rate Agreement is a binding contract, we find that
opining on that legal question would be antithetical to the instant task of
evaluating and rebalancing the equities in this Settlement Agreement.
Similarly, we find it in inappropriate to address the claim that the
subsidiary Sharing and Capacity Transfer Agreements have been breached.  Nor
is it legally required.  In its ruling on the transferred questions
concerning the Rate Agreement, the Supreme Court made it clear that the
ultimate test to be applied by the Commission in setting stranded cost
recovery is the public interest test as enunciated by the Restructuring Act:
whether the level of stranded cost recovery is "equitable, appropriate, and
balanced."  In re New Hampshire Public Utilities Commission Statewide
Electric Utility Restructuring Plan, 722 A.2d 483, 143 N.H. ___ (No. 98-114,
issued December 23, 1998).  The Supreme Court found that while it must
consider the State's obligations relative to the Rate Agreement in its
analysis, the PUC can award only those stranded costs that comport with the
standards mandated by the Legislature in RSA 374-F:4, V and VI. Id., 722 A.2d
at 488, Slip Opinion at 8.  The Legislature has further specified that the
Commission has the authority to consider the resolution of the stranded cost
issues by settlement. RSA 374-F:4, V.

2.   Specific Changes Required In The Settlement Agreement

     The Legislature has stressed that the outcome of any settlement
agreement must be balanced and in the public interest, and that the resulting
rates be "just and reasonable."  The Commission has determined that in order
to provide a more appropriate balance to this agreement, and fully satisfy
these requirements, certain parts of the Settlement Agreement must be amended
as discussed in the ensuing sections of this Order.

F.   ADJUSTMENTS TO STRANDED COST RECOVERY

1.   Accumulated Deferred Income Taxes (ADIT)

     The Company shall credit the ADITs related to the securitized assets at
the stipulated rate of return, rather than at the RRB rate, thereby
reflecting traditional regulatory treatment of these items.  Since a
utility's tax liabilities reflect its ability to utilize certain accelerated
depreciation provisions contained in the Internal Revenue Code, while its
rates reflect book depreciation, that utility will collect more for taxes
from current ratepayers than are needed to pay its current tax liabilities.
The difference between actual tax liabilities and actual tax collections is
carried on the utility's books as ADIT, where it is available to the utility
without restriction, and serves as a source of cost-free investment capital.
Once depreciation for tax purposes no longer exceeds that for book purposes,
ADIT is amortized until both the book value and tax value of the assets
amount to zero.  In the interim, in order to prevent utilities from earning a
return on these ratepayer-provided, cost-free sources of capital, traditional
regulatory treatment of ADIT reserves has been to deduct these amounts from
ratebase when computing the corresponding return on ratebase, in effect,
providing a credit to ratepayers at the Company's overall cost of capital.
Since PSNH is not proposing to provide a rate base deduction for the ADIT,
then all of the benefits of securitization are not being passed on to
ratepayers and the Company, not the ratepayer, will receive the interest
arbitrage for every regulatory asset that is securitized.  Therefore, Section
V (A)(3) of the Settlement Agreement is to be amended to provide a return on
the ADIT at a rate equal to the stipulated rate of return.  The record
indicates that the value of this adjustment is approximately $22.4 million at
the stipulated rate of return.

2.   Seabrook Sale

     The Commission is not persuaded by the testimony of Staff Advocates
witness McCluskey that PSNH should retain its Seabrook entitlement (after the
proposed buydown of NAEC's investment) for an extended period.  The market
for nuclear plants is rapidly developing, and the risks of nuclear plant
ownership cannot be ignored.  The Commission has determined, however, that it
would not be prudent for it to agree to be limited to the use of a comparable
transaction methodology for purposes of establishing a confidential minimum
bid, as provided in the Settlement Agreement.  Therefore, Section VIII (K) of
the Settlement Agreement, relating to the Commission's determination of a
confidential minimum bid, shall be modified to eliminate the phrase, "based
on comparable transactions and" from page 50, line 1420 of the Agreement.

3.   Regulatory Liabilities

     Under traditional ratemaking, the $65.6 million generation-related
regulatory liability accrued under FAS 109 and the $13 million deferred
receivable from NAEC identified by Staff Advocates witness McCluskey would be
credited to ratepayers over time.  The Settling Parties did not argue that
the treatment of these amounts were a "bargained for" item.  PSNH witness
Mahoney appeared to agree that these amounts would be credited to customers
as a rate base deduction (Ph. I, Tr. Day V, at 81:5), but PSNH's response to
a clarifying record request (Ph. I, Ex. 44) failed to verify that this would
occur.  Regardless of whether these items were "bargained for" by the
Settling Parties, these two items are not stranded costs and therefore
customers should receive the benefit of them as they would have under
traditional ratemaking.  Therefore, the Part 3 Stranded Costs shall be
reduced by $78.6 million to reflect a credit of these amounts.

4.   Hydro-Quebec Support Payments

     PSNH is a participant in the Hydro-Quebec ("HQ") inter-tie transmission
facility linking New England and Quebec, Canada.  The purchase and sale of
electricity from HQ is part of a series of agreements between HQ and various
New England utilities, including PSNH.  These agreements include a firm
energy contract, an energy banking agreement and a transmission support
agreement.  PSNH's firm energy contract and energy banking agreement end in
August 2000 and October 2001, respectively.  As a participant in the
transmission support agreement and in exchange for certain transmission
entitlements, PSNH is obligated to pay, over a 30 year period ending in 2019,
its share of the operating and capital costs of the transmission line - the
"transmission support payments."

     PSNH intends to auction its remaining HQ power and banking entitlements
and the associated transmission rights.  This auction is intended to occur
"on a timeline consistent with that for the fossil/hydro assets."  SA at
44:1265.  PSNH has assumed that the transmission rights have little or no
value because of the cost of the transmission support payments.  The
Settlement Agreement provides that the purchaser at auction is to assume
PSNH's responsibility for the contracts and for paying the transmission
payments.

     PSNH has argued that the transmission support payments are a stranded
cost, asserting that their cost is greater than the perceived market value of
the transmission entitlements.  In order to terminate its contract with HQ or
have another purchaser assume its contract, PSNH will therefore be required
to "buy down" the cost of the support payments.

     The Settlement Agreement provides that the cost of the HQ contract
buyout payments, without any offset from the sale of the facilities to a new
owner, is to be included in Part 3 Non-Securitized Stranded Costs and
recovered accordingly.  SA at 21:579.  The "buyout payments" reflect the "net
present value of the future obligations under that contract" for the
transmission support payments.  Ph. I, Day V at 62:11.  Appendix C to the
Settlement Agreement shows the net present value of this "buyout payment" to
be $62 million.

     In Order No. 22,512 issued in Docket No. DR 96-150 on February 28, 1997,
the Commission determined that the transmission support payments fell into
the category of transmission costs supporting a power purchase that was
potentially stranded, and permitted the above-market portion of this cost to
be reflected in interim stranded cost charges in a manner similar to that
allowed for above-market purchased power costs.  Now that the associated
power purchase is ending, however, the Commission finds that the transmission
support payments are better categorized as transmission-related rather than
generation-related, a conclusion PSNH admits is "a reasonable observation."
Ph. II, Ex. 186 at 24:21.  It must be considered, therefore, whether it is
appropriate to consider these costs as a "stranded cost."

     RSA 374-F:3, XII(d) provides that stranded costs "should not include
transmission and distribution assets."  The Commission has determined that
this section is intended to provide guidance to the Commission in addressing
claims for stranded costs, but it is not prescriptive, and was not meant to
preclude a case-by-case determination that stranded cost recovery for
particular transmission or distribution assets is warranted.  As we state
elsewhere in this Order, the overriding consideration is that the recovery of
stranded costs be balanced and in the public interest. Thus, we find that the
Commission is not precluded from allowing these costs to be recovered through
the SCRC if it were otherwise justified.

     We are concerned, however, that the proposed recovery of these costs
does not provide for an offset from revenues resulting from their sale at
auction.  This omission is contrary to the obligation of PSNH to mitigate its
stranded costs, pursuant to RSA 374-F:3, XII (c).  Moreover, even if such an
offset were provided, the timing of the proposed auction for these
transmission entitlements is inopportune.  As PSNH states in its rebuttal
testimony, "[T]ransmission service is evolving in New England and the United
States.  Several transmission issues are pending before the FERC, and the
Federal Appeals Court."   Ph. II, Ex. 186 at 31:13.  Under such
circumstances, the value of the line may be depressed.

     Though the FERC has not allowed the NEPOOL HQ participants to include
their HQ support payments in their regional open access tariffs, each of the
participants, including PSNH, have FERC approval for firm and non-firm point-
to-point tariffs for this facility.  The Commission finds that this line
could be used for the import or export of energy, and PSNH has an opportunity
to realize wheeling revenues that would offset at least a portion of its
support payments. (FN 24)  Though PSNH witness Mahoney testified that to
date, "no one has taken service over that line," he agreed that this could be
because the participating companies have been using it to transmit power for
their own HQ purchases. (FN 25)  Ph. I, Day V at 67:16.  If PSNH were to
auction its HQ entitlements at this time, the opportunity for offsetting
revenues would be lost.

     Therefore, PSNH will be denied stranded cost recovery for the HQ
contract buyout payments, without prejudice.  The Commission will allow PSNH
to renew its request for stranded cost recovery for this item in the rate
case to be filed at the end of the IDCP.  In the interim, PSNH will be
allowed to recover the HQ transmission support payments net of any offsetting
credit for all revenues received for usage of the line.  PSNH is required to
maximize revenues from this facility.  In order to allow recovery of these
expenses, within 10 calendar days of the date of this Order, PSNH is required
to file schedules showing the actual cost of the transmission support
payments over the last three years, and a proposal to recover its costs,
including a means to account for any revenue offsets.

5.   Reconciliation and Recalculation of the SCRC

     During the course of the hearings, several significant matters were
discussed where it was not clear whether the Company's financial model
accurately reflected the intent of the Settlement Agreement, whether the
financial model itself contained inaccuracies, or whether the Settlement
Agreement itself was silent and a particular course of recovery and
reconciliation was assumed, but not spelled out.  As the SCRC is derived from
the PSNH model, it is critically important that the proper calculations be
made; otherwise the SCRC will be either too high or too low.

     The Commission's analysis of the changes to the level of stranded costs
approved in this Order results in an estimated SCRC of $0.034 per kWh.  Since
we do not have the PSNH model for these calculations except to the extent
certain elements were described in testimony, we have approximated the
results, but for accuracy in the tariffs we will direct PSNH to make a
compliance filing within 10 calendar days of the date of this Order employing
its financial model. This filing shall incorporate the changes to stranded
costs as we have indicated, and should provide the SCRC based on these
changes as outlined in Exhibit 86 from Phase I.  In addition, this filing
shall incorporate corrections for the following items, agreed to by PSNH
during the hearings:

a.   NOx Credits

     PSNH received approximately $24.5 million from the sale of certain NOx
allowances during 1998.  During 1999, $13.5 million of these credits were
used to support capital projects at Merrimack and Schiller generating
stations.  The remaining $11 million is recorded on PSNH's
books as a regulatory obligation.  The Commission finds that these amounts
are to be credited to ratepayers as PSNH has represented in Phase I, Exhibit
No. 71.  Once Merrimack and Schiller are divested, capital additions funded
by the proceeds of the sale of the NOx credits shall be excluded from the
cost basis of the plant when calculating stranded costs.  The remaining $11.5
of NOx credits proceeds are to be credits to Part 3 stranded costs.

b.   Loss On Reacquired Debt

     The Loss on Reacquired Debt is the loss occasioned or the premium
payment required when debt is retired early.  Non-Settling Staff witness
Kosnaski testified that there appeared to be a double recovery of a portion
of this amount through recovery in both the Part 3 stranded costs and payment
out of the securitization proceeds.  The Company admitted that there appeared
to have been incorrect assumptions included in its modeling of this item.
Ph. II, Tr. Day XIX, at 228:4.  The Company is directed to correct its filing
to remove unamortized loss on reacquired debt from Part 3 stranded costs.

c.   Updating Of The FPPAC Deferral

     The FPPAC Deferral, recovered as a Part 3 stranded cost, must be
adjusted to reflect balances as of July 1, 2000.  No further adjustments for
potential benefits of the Sharing and Capacity Transfer Agreements are
required.  As indicated in the Settlement Agreement on page 34, the recovery
of PSNH's FPPAC balance as of August 2, 1999, shall not be subject to a
prudence determination.  However, the recovery of any FPPAC accruals that
occur after August 2, 1999, shall be subject to the prudence standard of the
Agreement and shall reflect the revenues from off-system sales and other
standard FPPAC adjustments.

6.   Recovery End Date "Cushion"

     PSNH testified that a five-month "cushion" was built in to the Recovery
End Date in order to provide the Company's accountants some reasonable
assurance of recovery of Part 3 stranded costs.  Phase 1, Tr. Day X, at
117:8.  Under the original set of assumptions in PSNH's financial model, the
Company expected to fully recover its Part 3 stranded costs by early May,
2007.  The five-month "risk adder" brought the agreed upon Recovery End Date
to September, 2007. Subsequently, in Phase I, Exhibit 39, PSNH stated that
"the risk negotiated added timeframe of five months has been reduced to two
months" as a result of certain changes.  Exhibit 39 calculated the changes to
the financial model output reflecting the Vermont Yankee sale and the NHEC
settlement.  With the changes made in this exhibit, the Part 3 stranded costs
are projected to be recovered by the end of July, 2007.  This leaves a two-
month "risk-adder" for PSNH.

     The Commission has determined that once the SCRC has been recalculated,
the Recovery End Date "cushion" or "risk-adder" shall be no more than two
months.  PSNH is directed to recalculate the Recovery End Date in accordance
with the terms of the Settlement Agreement, the recalculated SCRC and the
limitation of a two-month "cushion."  As part of this recalculation, the
Settling Parties are directed to propose a specific readjustment of the RED
to account for the removal of the HQ transmission support payments from Part
3 Non-Securitized Stranded Costs.

G.   SECURITIZATION OF STRANDED ASSETS

1.   Overview

     The Settlement Agreement petitions the Commission for the authority to
issue a total of $725 million in rate reduction bonds to finance a portion of
the Company's stranded assets in a financial transaction known as
securitization.  Under 1999 N.H. Laws, Chapter 289, Section 3, the Commission
is permitted to consider securitization of stranded costs and to issue a
conditional securitization order.  As a condition to implementation, the
Settlement Agreement requires the passage of acceptable securitization
legislation and the successful completion of the proposed bond issue.  SA at
60:1715-1718.

     PSNH plans to use the proceeds of securitization to buy down its capital
structure, replacing higher cost debt and equity with lower cost, Triple-A
rated rate reduction bonds (RRB), thereby reducing financing costs.  The
Settlement Agreement calls for the securitization of four principal
categories of stranded assets: 1) the over-market value of the Seabrook
nuclear asset;  2) the over-market value of the Millstone 3 nuclear asset;
3) a portion of the Acquisition Premium and its corresponding tax gross-up;
and 4) the costs of deploying the proceeds of securitization (i.e., bond
premiums or "loss on reacquired debt") and certain issuance costs related to
the transaction.

2.   The Mix of Assets Being Securitized

     The Settlement Agreement allows PSNH to securitize a total of $725
million of its assets. The Company originally proposed to securitize: $506
million of the Seabrook asset; $84 million of the Millstone asset; $74
million of acquisition premium; $44 million of deferred taxes related
to the acquisition premium; and $17 million related to bond premiums and
issuance costs.  SA at 78.  These amounts were based on a Competition Date of
January 1, 2000.  Competition Day is now assumed to occur on or after July 1,
2000; therefore,  these assets are continuing to be recovered from existing
rates and the net book balances of these assets will be lower as a result of
six or more additional months of amortization.  Exhibit 86 in Phase I shows
that as of July 1, 2000, the net book balances of Seabrook and Millstone
over-market costs, as well as the stranded costs associated with the
Acquisition Premium and the FAS 109 part of the Acquisition Premium decreased
by $37 million.

     The Settlement Agreement states that the amount of Acquisition Premium
and related FAS 109 taxes to be securitized will be measured as the
difference in the proceeds from RRBs and the net book value of the Seabrook
and Millstone nuclear assets.  SA at 19:523-525.  In other words, if
Competition Day occurs later than assumed, the Settlement Agreement keeps the
level of securitization the same as assumed for modeling purposes.  It
accomplished this by simply treating the Acquisition Premium and FAS 109
taxes as a "slack variable" in the securitization equation, making the sum of
the securitized portion of the Seabrook/Millstone assets, issuance/deployment
costs and the securitized portion of the acquisition premium/FAS 109 taxes
total $725 million.

3.   Analysis

     With the exception of CRR, who questions the value and the amount of
securitization in the Settlement Agreement, most parties in this proceeding
agreed that securitization offered the opportunity to produce meaningful cost
savings for New Hampshire ratepayers.  Some parties, such as the City of
Manchester and the OCA, however, question the level of securitization
proposed in the Settlement Agreement.  The City of Manchester also raises its
concern about the use of funds by NU after securitization.  In particular,
the City warns of market power problems if NU uses proceeds to purchase
generating facilities.  Manchester Br. at 32.  OCA considers securitization a
zero sum game, at best, and suggests that securitization should only be used
on assets that would have had a high likelihood of being recovered from
ratepayers, such as the above-market cost of the Seabrook Power Contract, or
for savings achieved through SPP buydowns or buyouts.  OCA Br. at 11-12.  Mr.
Kosnaski, testifying on behalf of Non-Settling Staff, states that
securitization is responsible for a $54.6 million decline in annual financing
costs in the first full year of its implementation, or about 7.1 percent of
the total 18.3 percent rate reduction promised under the Settlement
Agreement.  Ph. II, Ex. 142, at 13.

     Once a level of stranded costs is determined, it is in the interest of
ratepayers to reduce the financing charges as those costs are recovered over
time.  Securitization is a means of achieving that reduction.  It does so by
reducing risk to the Company.  The Commission, after careful examination of
the record, finds that securitization in this case would offer significant
cost savings to PSNH's customers.

     While recognizing the benefits realized by securitization to both
ratepayers and the Company, the Commission does not agree that the specific
securitization proposal embodied in the Settlement Agreement meets the
requirements of 1999 N.H. Laws, Chapter 289:3,I (FN 26) without certain
changes.  As discussed in Section VIII (F)(1) of this Order, our first
condition is that the Company provide a credit at the stipulated rate of
return for ADIT balances it holds on behalf of ratepayers.

     Next, we determine that the term "Stipulated Rate of Return"
incorporates a return on equity of 8 percent after tax, an equity ratio of 40
percent, and the weighted cost of PSNH's nonsecuritized long-term debt, as
provided in the Settlement Agreement at 10:268.  Therefore, it is not
necessary that we condition our approval of the Settlement Agreement on PSNH
actually attaining a 40 percent equity ratio through utilization of
securitization proceeds.

     Third, certain modifications of the Settlement Agreement are necessary
to address the market power concerns highlighted by the City of Manchester
with regard to the use by NU of proceeds from securitization.  We note that
Mr. Long testified in Phase II, "NU is not out there purchasing power plants
or building them ...," Ph. II, Tr. Day XVIII, at 222:21-22, and that neither
PSNH's affiliate, Select Energy, nor Consolidated Edison, intends to be a
"major generation owner," although they do intend to own a small amount of
generation to protect against market fluctuation.  Ph. II, Tr. Day XIX, at
283:5-6.  We explicitly rely on these representations in arriving at our
findings as to the extent to which the Settlement is in the public interest.
Also, we note PSNH's commitment in the Settlement Agreement at lines 1691-
1692 to "cooperate to establish market power measurements and benchmarks that
may be used to monitor how the ISO-NE power marketplace is operating."  With
certain modifications, this commitment should help to forestall the problems
to which the City alludes.  First, NU must join in the commitment, because
PSNH is not a member of NEPOOL.  Second, the phrase "that may be used" must
be replaced with the phrase "that will be effective," so as to inject a
substantive standard for the fulfillment of NU/PSNH's commitment.  While we
do not require NU or PSNH to sponsor a particular market power assessment or
mitigation tool, we note that a price baseline, modeled to simulate the
outcome expected in a perfectly competitive market, can be a valuable tool to
identify abuses of market power.  Finally, we will require PSNH to file
reports quarterly with the Commission, during the IDCP, of the positions NU
or any NU affiliate has taken on market power monitoring and mitigation
efforts in NEPOOL, before the ISO or before FERC.

     Finally, we condition our approval of the Settlement Agreement on an
amendment to the manner in which the acquisition premium and corresponding
FAS 109 regulatory asset are included in the balance of securitized stranded
assets.  Specifically, we note that as a result of Competition Day occurring
on or after July 1, 2000, rather than January 1, 2000, book balances related
to securitized stranded assets will continue to be written down reflecting
amortization of these balances as revenues are received from ratepayers
reflecting recovery of a portion of these assets.  The net book balances of
the four securitized stranded assets as of July 1, 2000 will be approximately
$37 million less than they were on January 1, 2000.  Accordingly, we believe
that it is appropriate to reduce the total level of securitization by $37
million, thereby approving a securitization level of $688 million, which
includes the $17 million for issuance expenses.

However, if the Company is able to negotiate reductions in its existing SPP
rate order obligations, as set forth in Section VIII (P)(6) and of this
Order, we will consider allowing an additional amount of securitization up to
$37 million.  This $37 million decrease in securitized stranded costs will be
shifted back to Part 3 stranded costs.  We recognize this changes the PSNH
model shown in Phase I, Exhibit 86.  Therefore, we expect PSNH to reflect
these changes in its reconciliation filing.

H.   STRANDED COST RECOVERY CHARGE

1.   Overview

     Until the earlier of the Recovery End Date or the date that non-
securitized stranded costs are fully amortized, the Settlement Agreement
provides that the Stranded Cost Recovery Charges ("SCRC") will be calculated
to produce an overall average rate of $0.0379 per kWh, and this overall
average will not be subject to change.  The Settlement Agreement was largely
silent on the specific design of class-by-class charges, and rate design
within charges, subject to the overall parameters identified in the Rate
Design section, below.  PSNH filed proposed tariffs that reflected its
desired rate design.  The other signatories did not express an opinion on the
PSNH proposal.

     In the Company's proposal, the specific SCRC for each class varies,
because the SCRC is essentially a "plug" number.  That is, PSNH proposes that
the SCRC for each class be a residual amount, defined by deducting certain
non-varying charges and class-differentiated delivery charges from the target
average class rate.  The Company makes certain adjustments to this basic
formula to deal with anomalous situations, but the general result of the
Company's rate design proposal is an SCRC that varies by class in such a way
as to produce for the class an overall target percentage rate reduction as
specified by the Agreement.

     No party other than OCA proposed any alternate design, although BIA did
request that the Company's proposed design be locked into place beyond the
initial delivery charge period.

2.   Analysis And Findings

     The Restructuring Statute provides that the result of stranded costs
must be recovered through "a nonbypassable, nondiscriminatory, appropriately
structured charge," and one that is "fair to all customer classes, lawful,
constitutional, limited in duration, consistent with the promotion of fully
competitive markets and consistent with [the statutory restructuring]
principles."  RSA 374-F:3, XII (d).  The statute also disfavors exit fees,
and makes other limitations on SCRCs to jurisdictional retail customers, and
those particular requirements have been observed in the Settlement Agreement
and the proposal put forth by PSNH to implement it.

     OCA's challenge to the fundamental design of Stranded Cost Recovery
Charges as proposed by the Company raises important questions under the
restructuring statute.  With respect to the OCA's proposal for an adjustment
to the SCRC to accommodate a retail adder, the Commission has declined to
require the signatories to amend the Agreement to include a retail adder. See
Section VIII (I)(2) of this Order.  Accordingly, it is not necessary to
consider further adjustments to the SCRC design on this account.  The general
topic of retail adders is addressed more fully in our Order under the topic
of Transition Service.

     The proposal of the OCA that SCRCs be developed on an equal cents per
kWh basis, and the related proposal to fix "buckets" of stranded cost
recovery amounts by class, merit further consideration.  As Mr. Traum noted
in his testimony, the Commission in its Final Plan in DR 96-150, February 28,
1997, determined that, consistent with RSA 374-F:3, XII (d), "utilities shall
allocate recoverable stranded costs to all customer classes using existing
cost allocation methodologies for generation assets."  The Company
acknowledged during the hearings that it had not used a cost of service study
to allocate stranded costs to classes.  Rather, the Company used the residual
method described above to develop SCRCs and the resulting allocation of
recoverable costs to classes.

     The question is whether the Company's mechanism produces results which
are reasonably close to the outcome that could be expected from a cost of
service study.  In 1999, the Legislature enacted 1999 N.H. Laws, Chapter
289:6 to amend 374-F:4, V, to permit SCRCs to be implemented in the context
of a settlement agreement, as opposed to a full rate case.  For that reason,
we need not insist that the results of the Company's recovery mechanism
produces exactly what would be expected by using a full cost of service study
in a litigated rate proceeding. Further, after the IDCP, as the signatories
agree, the Commission may revisit the design of SCRCs by class and within
classes, and can amend the design if a full cost of service study or other
suitable allocation study dictates.  However, we are mindful of the BIA's
caution that instituting a particular SCRC design today, and then radically
altering it in the future, could undermine rate continuity.

     Hence, the SCRCs resulting from the residual calculation developed by
the Company must be examined to determine how well they comport with what
would be expected from a proper allocation of such costs.  While the Company
offered no study or analysis on this topic, Dr. Stutz examined each component
of stranded costs on behalf of OCA, and offered his analysis of the proper
basis for allocation of costs and rate design.

     Dr. Stutz focused on three groups of costs: (1) over-market generation
assets and deferred returns associated with Seabrook, as well as other
stranded assets associated directly with generating facilities; (2) the PSNH
Acquisition Premium and other financing-related costs in the stranded assets;
and (3) the costs which otherwise would flow through the Company's FPPAC.
With respect to Seabrook, Dr. Stutz observed that it was designed and built
as a baseload generating unit.  Dr. Stutz argues that the plant has become a
source of stranded costs because the investment made to produce energy did
not prove economic, and hence he classified the over-market generation assets
of Seabrook as energy-related, and proposes that they be recovered on a
uniform, cents per kWh basis.

     PSNH disputed Dr. Stutz' related assertion that such Seabrook costs were
being recovered today on an equal cents per kWh basis via the FPPAC.  Whether
costs are recovered in one or another manner today is not dispositive in
either direction.  As we said in the Final Plan, the question is the proper
cost allocation for the underlying costs that have become at risk of
nonrecovery.  The Commission has not utilized a cost of service study to set
PSNH's rates in almost ten years.  Since then, base rates have been adjusted
either for equal percentage increases for each class under the Rate
Agreement.  As this method was the result primarily of negotiation of the
1989 Rate Agreement, it cannot be relied on to dictate cost allocation and
associated rate design for stranded cost recovery.  Thus, we must return to
basic rate design principles.

     As Dr. Stutz explained, both marginal cost rate design principles and
cost-causation principles support his proposed energy-based Seabrook cost
SCRC component.  However, Dr. Stutz conceded on examination by the bench that
even under his approach, certain Seabrookrelated investments were capacity-
driven.  Dr. Stutz agreed that it was possible to isolate the proportion of
the plant associated with capacity costs, by backing out from the total net
book cost the value of a peaker, and at the request of the bench, he
performed this calculation in Ph. II, Ex. 59.  This factor warrants
consideration of allocating some Seabrook-related costs on a non-energy
basis.  Also, over time, various cost allocation methods, ranging from
coincident peak to probability of dispatch, have been used by this and other
commissions to allocate baseload production plant costs, and application of
such other methods could well produce a different result from either Dr.
Stutz' recommendation or the Company's proposal.

     Without further examination of the allocation question raised by this
facet of Dr. Stutz's testimony, we would be reluctant to decide as a fixed
policy matter that all Seabrook-related costs be recovered on an equal cents
per kWh basis.  The same analysis applies to stranded costs associated with
Millstone 3 over-market costs and Vermont Yankee termination findings, and to
the Fossil/Hydro credit, which Dr. Stutz proposed to spread back on a uniform
per kWh basis on grounds of "horizontal equity."  Thus, we find much merit in
Dr. Stutz' approach regarding these costs, but cannot require on this record
that it be substituted in its entirety for that resulting from the Company's
mechanism.

     With respect to the NU-PSNH Acquisition Premium, we agree with Dr. Stutz
that fairness requires that these costs be recovered on an equal cents per
kWh basis, in the absence of a compelling argument to the contrary.  Similar
considerations apply to the unamortized loss on reacquired debt, and the
financing costs.  Also, stranded costs that have been recovered through FPPAC
on an equal cents per kWh basis should be recovered, all else being equal, in
a similar manner in the SCRC.

     Because of the state of the discussion of cost allocation issues on this
record, we are not in a position to adopt Dr. Stutz' recommendation fully and
permanently.  Neither can we accept the PSNH proposal, which produces extreme
differences in SCRCs between classes.  For example, under the PSNH proposal,
the residential class would pay an SCRC approximately 40 percent higher than
large general customers, and 400 percent higher than special contract
customers. Such differentials in SCRC charges are inconsistent with sound
cost allocation, and cannot be squared with the statutory requirements.  In
anticipation of redesign of the SCRC after a full examination of the issue in
a rate design proceeding, and to prevent severe dislocation in prices at that
time, it is necessary to identify a middle ground between the two approaches.
Such a result would incorporate some reflection of fair cost allocation
principles, without adopting the OCA analysis in its entirety on this record.

     We have determined that, for the IDCP, the SCRC should be based on a
melding of Dr. Stutz' approach and the Company's mechanism, by adjusting the
SCRC for each class, as an initial matter, to a point halfway between the
SCRC produced by the Company's mechanism and an equal cents per kWh basis as
proposed by OCA.  The first year class-by-class results of such an approach,
assuming an overall average SCRC of $0.0340 per kWh, and a Transition Service
price of $0.040 per kWh, an estimated 1 mil per kWh recovery of HQ payments,
and using the Company's proposed Delivery Charge and other charges as
specified in the Agreement, are shown in the table in Section P(10) of this
Order, below.

     The allocation of costs to classes according to this melding of the
Company's mechanism and an equal-cents-per-kWh basis will ensure that, even
in the initial period when rates are in effect, each class is contributing an
amount that better approximates the stranded cost amount that would result
from a full cost of service study and allocation process. All parties will
have an opportunity to make their arguments as to the proper underlying
allocation of such costs in the rate design case anticipated to accompany the
Company's delivery service rate case filing in 30 months.  Further, we expect
that the Company, in its compliance tariffs filed in the event the
signatories accept the conditions set forth in this Order, will propose
specific rate class tariffs that accommodate the inter-class transition
problems it has identified with respect to the general service classes, and
the elimination of the negative energy charge that would otherwise occur in
the case of certain rates already discounted.

I.   TRANSITION SERVICE

     Section V(D)(2) of the Settlement Agreement sets forth the provisions
regarding Transition Service.  The issues that arose during the hearings
surrounding Transition Service primarily concerned the prices at which it is
to be offered under the Settlement Agreement. Related to these prices,
however, are a number of other issues: whether a competitive market will
develop if these prices are used; whether the use of these prices would lead
to significant deferrals; whether deferrals should be reduced or even
allowed; whether it would be better and consistent with the law to base
Transition Service prices on market prices; and whether retail adders should
be used to assist in the development of the retail market.

1.   Transition Service Price

     The Commission finds the weight of the evidence in the docket supports a
conclusion that the transition prices included in the Settlement Agreement
are too low.  It is more likely than not that the price of providing
Transition Service will exceed the prices included in the Settlement
Agreement and will therefore produce deferred costs that would be recovered
from ratepayers by extending the time period for recovering Part 3 stranded
costs.  We find, therefore, that the prices for Transition Service must be
adjusted upward.  While the idea of directly passing through market prices
for Transition Service is appealing for a number of reasons, our conclusion,
supported by RSA 374-F:3,V(b), is that Transition Service prices should be
stable, predictable and rise over time to encourage customers to choose a
competitive supplier.  We interpret this provision as directing us to
establish a price for Transition Service rather than to use a purely market-
based price.  In addition, 1998 N.H. Laws, Chapter 191, Section (2)(IV)
provides that the Commission should "ensure that the terms of transition
service accomplish the principle of near term rate relief while taking into
account the need for developing customer choice."

     Given these requirements and the evidence in this proceeding with regard
to market prices, the Commission conditions its approval of the Settlement
Agreement on a change in Transition Service prices to $0.040, $0.041, and
$0.042 per kWh over the same period of time detailed in the Settlement
Agreement.  Although we can not predict what the prices for Transition
Service will be, we believe, based on the record before us, that the
increased prices which we have adopted will bring the Transition Service
price closer to a market rate.  These prices will encourage the development
of a competitive market to a greater degree than would be the case under the
prices in the Settlement Agreement.  In addition, this change will still
provide stable and predictable prices and the near term rate relief
referenced in legislation.  One other beneficial byproduct of this change
will be a reduction in deferrals.  Although there is still the possibility
that deferrals will be produced, this change should significantly reduce
them.

2.   Retail Adder

     The Commission is not persuaded that it would be in the public interest
to include retail adders as a means of assisting in the development of the
competitive market.  Use of a retail adder would run contrary to the near
term rate relief principle and would be an artificial and unnecessary means
of trying to encourage the development of the market.  In addition, retail
adders could result in shifting some stranded cost burden from shopping
customers to non-shopping customers.   In our opinion, this is not an
effective way of encouraging market development.

3.   One Transition Service Rate

     Since Transition Service is a temporary service, and it is difficult at
this time to predict how the market will develop for different classes of
customers, the best approach is to provide one Transition Service price that
applies to all classes of customers, as provided in the Settlement Agreement.
As provided in the Settlement Agreement, however, different classes of
customers will be treated differently in their ability to return to
Transition Service once they have left to be served by a competitive
supplier.

4.   Use of Existing Resources

     Several parties have suggested that existing PSNH resources be used to
provide Transition Service for an interim period.  RSA 374-F:3,V(b) provides
that Transition Service "should be procured through competitive means...."
This provision was elaborated upon by the Legislature in 1998 N.H. Laws
191:1,V(b), which states that procuring through competitive means includes
the "option of having transition service supplied by the current owner of
such generation assets while the sale is pending...."  In light of this
provision, it is clear that use of existing resources for the provision of
Transition Service is consistent with the Legislature's intention.

     The Commission finds that it is reasonable to allow PSNH to utilize its
existing resource portfolio for the provision of Transition Service for a
limited period of time (rather than engaging in market transactions to
dispose of its resources pending divestiture) because it will eliminate the
administrative expenses associated with those market transactions and one of
the many additional tasks created by restructuring.

     In addition, interim use of the current resources, including IPP power
and PSNH ownedfacilities or entitlements will further assist in reducing
deferrals.  For all of these reasons we believe that it is appropriate and
beneficial to use existing resources on an interim basis to provide
Transition Service.  This "interim period" should be a limited one, dependent
on the length of time it will take to procure Transition Service and the
length of time to divest certain generation assets. Based upon the estimates
of when these actions will occur, the Commission finds that existing
resources should be used between Competition Day and January 1, 2001.  The
Commission reserves the authority to modify that date based on how these
processes unfold over the next few months.

     PSNH shall be responsible for any excess resources in accordance with
Section IX of the Settlement Agreement.  If PSNH's assets are sold prior to
that time, PSNH will be responsible for providing Transition Service from
market resources.

5.   Transition Service Bidding

     The Commission finds that the process outlined by the Settling Parties
for awarding Transition Service is appropriate.  Affiliates of PSNH will not
be prevented from bidding. Because a PSNH affiliate intends to bid on
Transition Service, it is appropriate to require PSNH to hire an independent
consultant to conduct the process for acquiring Transition Service, and to
provide Commission Staff with plenary oversight authority.  This action is
taken in order to provide bidders and customers with the maximum assurances
that Transition Service will be procured through as fair a process as is
practicable.

     There may be more than one round of bids, and Transition Service may be
awarded to more than one bidder.  Three different providers of Transition
Service seems appropriate to us at this point, but we reserve the right to
make a final decision on that issue based on the advice of the independent
third party that conducts the auction process.  Branding is appropriate and
will be permitted.  We expect it to improve the result.

     The remaining terms of Transition Service, including the provisions
concerning the ability to return to the service, the provisions for
assignment of customers at the end of the period, and the provisions for
recovery of administrative costs provided for in the Settlement Agreement are
appropriate.

     Finally, the three year period for Transition Service provided for in
the Settlement Agreement is consistent with RSA 374-F:3, V(b) which provides
that "transition service should be available for at least 2 years but not
more than 4 years after the start of competition...".  The Settlement
Agreement also tracks other provisions of the same law by making separate
provision for default service.  Although the Commission is concerned about
the level and volatility of prices for default service, the proposal is
consistent with the law and we therefore approve it.

J.   DELIVERY SERVICE RATE

     The rate proposed by the Settlement Agreement for delivery service is an
average of $0.028 per kWh for the 30 months of the Initial Delivery Charge
Period (IDCP).  This charge remains in effect until changed by the Commission
following a delivery service rate case after the IDCP.  PSNH will file such a
rate case not later than 29 months following Competition Day, and will
utilize the most recent four quarters of data on which to base the request
for a new delivery rate.  That new rate ultimately established by the
Commission shall be made effective at the conclusion of the 30 month IDCP.

     During the IDCP, PSNH will establish a Major Storm Cost Reserve and fund
it in the amount of $3 million per year.  Major storm costs will be charged
to this reserve during the IDCP.  As part of its delivery charge rate case
PSNH will report any difference in the actual costs charged to the reserve
and the funding of the reserve.  PSNH will be entitled to recover, or be
obligated to refund over the 12 months following the IDCP, or such other
period ordered by the Commission, any difference between the amounts charged
to the reserve and the funded amount of the reserve.

     In addition, PSNH has established an Environmental Reserve for
expenditures for sites as identified in the Agreement.  This reserve is
expected to total $11.5 million as of Competition Day, and during the IDCP
PSNH will charge its actual environmental remediation expenses to the
reserve.  Subsequent to the IDCP, PSNH will recover or refund any difference
over a period not to exceed three years, subject to a prudence finding for
the costs charged thereto.

     At hearing, we heard testimony from Non-Settling Staff witness Mark
Naylor applicable to delivery service.  Mr. Naylor provided testimony that,
depending on the methodology chosen for analysis, the Company would have a
reasonable opportunity to earn its allowed return with a delivery rate of
from $0.0267 per kWh to $0.0275 per kWh.  PSNH has provided testimony that,
at $0.028 per kWh, the Company would need to reduce expenditures or increase
revenues in a range of from $10 million to $14 million annually in order to
earn its rate of return on its delivery service rate base during the IDCP.
Absent these adjustments, the Company avers that its delivery rate would have
to be in the magnitude of $0.030 per kWh for the Company to earn a reasonable
return.  The Settling Staff and the GOECS have provided testimony that the
average delivery charge of $0.028 per kWh is compensatory to PSNH, based on
their analysis using a rate of return on equity of 10 percent.

     We are prepared, based on the record, to accept the average delivery
rate of $0.028 per kWh for the 30 months of the Initial Delivery Charge
Period.  Considering the varying impacts of a number of components affecting
the rate, such as sales forecasts, equity return, treatment of
storm costs, and the phase out of generation-related Administrative and
General costs, we believe that the $0.028 per kWh average rate is just and
reasonable in the context of the overall Settlement considering the
adjustments to stranded cost recovery that we have required to balance the
equities.  The delivery service revenue requirement will be fully analyzed
during the rate case to follow the IDCP. We will review that rate after the
IDCP, when PSNH's generation business has been divested and the Company has
become a delivery-only business.

K.   CONSOLIDATED EDISON/NORTHEAST UTILITIES MERGER

     Section XIV (C) of the Settlement Agreement provides that if NU is
acquired or merged within 5 years of Competition Day it agrees that
"notwithstanding any contrary provision of law, the merger, acquisition or
sale shall be subject to the jurisdiction of the PUC under RSA Chapters 369,
374, 378 or other relevant provisions, and that the merger, acquisition or
sale shall be approved only if it be shown to be in the public interest."
Immediately prior to the first day of hearings in this docket, NU announced,
on October 13, 1999, a proposed acquisition by ConEd. On January 18, 2000
ConEd and NU filed a petition with the Commission seeking approval of the
proposed acquisition of NU by ConEd.  (Although the petition refers to the
transaction as an acquisition, most parties have referred to it as a merger
and we will therefore use that term throughout.)  The Commission has docketed
this separate proceeding as DE 00-009 and has established a separate
procedural schedule to consider the petition.

     PSNH and the Settling Parties have argued that the merger is a separate
and independent proceeding and ought to be treated as such.  PSNH has also
argued that the standard of review for the merger articulated in Section XIV
of the Settlement Agreement is not a higher standard for approval than what
is already provided for in the law, nor is it any different than the standard
that the Commission has used since 1991, understood as the "no net harm"
standard.  PSNH has also argued that lines 433-438 of the Settlement
Agreement would prohibit the Commission from adjusting the delivery service
rate during the 30 month IDCP to account for merger costs and savings.  While
the Settling Staff and the GOECS agree with PSNH that the Commission should
treat the merger separately, they disagree with PSNH on two points: 1) they
believe that the language of Section XIV (C) gives the Commission broader
review authority than the "no net harm" test which the Commission has
traditionally used and argue that the intent was to impose a "positive
benefit" test; and 2) they believe the Settlement Agreement may be
interpreted, or conditioned, to allow any savings resulting from the merger
to be passed on to ratepayers during the IDCP.

     It was argued by several of the non-settling parties, including the
Staff Advocates and City of Manchester, that the Commission should directly
condition PSNH's stranded cost recovery on the outcome of the review of the
merger, and should take into account the merger premium received by NU
shareholders when making a final determination of stranded cost recovery.  It
is the Staff Advocate's recommendation that the Commission should determine
in this docket a specific formula or establish principles to govern the
manner in which the acquisition premium would be taken into account.

     Based upon the conflicting testimony of the State Team and PSNH, it is
apparent that there has been no "meeting of the minds" of the signatories on
the issues of the standard of review of the merger and whether merger savings
may be required to be passed through to ratepayers during the 30-month IDCP.
Therefore, we find that there is no agreement between the Settling Parties on
these matters.  As a result of the Commission's determination with respect to
lack of agreement between the State Team and PSNH, there is nothing in the
Settlement Agreement that would prohibit the Commission from taking action on
these questions in the context of the merger docket.

     The Commission also finds that there is insufficient evidence in this
record concerning the details of the proposed merger to resolve the issues
raised by the various parties.  Accordingly, we will defer to Docket DE 00-
009 the particular questions concerning the standard of approval by which the
transaction is to be reviewed and the nature and extent of any conditions
that should be placed on our approval of the merger.  We will take
administrative notice in Docket DE 00-009 of the record in this docket to
preserve the record on these issues.

L.   ASSET DIVESTITURE

     The Commission finds the Settlement Agreement's stated goal of
maximizing the net proceeds realized from the sale of PSNH's power generation
assets and purchased power agreements in order to mitigate stranded costs to
be consistent with the relevant provisions of RSA 374-F and therefore in the
public interest.  However, certain provisions contained in the Settlement
Agreement that specify the manner in which the Settling Parties purport to
achieve the aforementioned goal must be modified, primarily due to events
that have transpired subsequent to the filing of the Settlement Agreement.
Those events include the proposed merger of Consolidated Edison and Northeast
Utilities, as well as PSNH's modified position concerning
the ability of an affiliated entity to bid on PSNH's generation assets.  In
addition, we find it necessary to impose conditions for purposes of clarity
and sound public policy.

1.   Affiliate Bidding, Role Of Independent Consultant, PUC Oversight

     Although the Settlement Agreement (SA at 40:1151) states that "PSNH
affiliates will be entitled to bid in the fossil/hydro asset auction," PSNH
Witness Long testified that the Company would be willing to accept a
condition "to restrict Northeast Utilities from bidding on the plants" and
that this was a "very significant material change."  Ph. II, Tr. Day XVIII,
at 218, 221.  The Commission finds that the public interest would be served
best if PSNH affiliates are precluded from bidding on PSNH's generation
assets.  This ban would also apply to Consolidated Edison companies if its
proposed merger with Northeast Utilities is finalized prior to the initiation
of the divestiture process.

     This approach will promote a fair and non-discriminatory process and
will assist in fostering a truly competitive generation market, unfettered by
concerns over affiliate transactions, self-dealing and related issues.  In
addition, such a prohibition obviates the need for a code of conduct and
heightened Commission oversight, and reduces the administrative burden and
expense associated with divestiture.  Although this approach eliminates one
category of bidders which theoretically could reduce the ultimate purchase
price of the assets, we believe that this potential for impact on the
purchase price is outweighed by the aforementioned benefits of banning
affiliate bidding.

     Because it is not certain that the proposed merger of Consolidated
Edison with Northeast Utilities will receive all necessary approvals - either
prior to the commencement of the asset sale process, or at all - we do not
believe it is appropriate at this juncture to ban Consolidated Edison
companies from bidding on PSNH assets during the pendency of the merger
proceedings. However, the inclusion of a prospective PSNH affiliate into the
asset bidding process raises concerns that we believe can best be addressed
by requiring PSNH to hire an independent consultant to conduct the asset
sale.

     If Consolidated Edison does not intend to bid on PSNH's assets, we find
that an outside consultant will not be necessary and therefore we will permit
PSNH to proceed with divestiture in the manner prescribed by the Settlement
Agreement as modified by this order.  In order to determine whether PSNH must
proceed with hiring an independent consultant for divestiture management, we
direct PSNH to inquire of Consolidated Edison whether any of its companies
intend to bid on PSNH's assets.  PSNH shall furnish the Commission with a
written response from Consolidated Edison no later than two weeks from the
date of this Order.  If Consolidated Edison indicates an intent to bid or an
unwillingness to make its intentions known by the date indicated above, PSNH
must hire an independent contractor that is acceptable to Commission Staff.

     We expect that an independent divestiture manager coupled with the
Settlement Agreement's provisions concerning "blind bidding" and the
respective roles of the designated financial advisor and PUC staff (or
consultants hired by the Commission), as outlined in the Settlement Agreement
at Pages 40-41, will insure that Consolidated Edison receives no preferential
treatment during the divestiture process.  However, because the Settlement
Agreement was filed prior to the proposed merger announcement, it is unclear
whether the Settling Parties considered the case of a prospective affiliate
bidder.  Accordingly, given the pendency of the proposed merger between NU
and a potential bidder on PSNH's generation assets, we order PSNH and NU to
take whatever additional steps are necessary (including, but not limited to
adopting a code of conduct in consultation with PUC Staff)  to make the asset
divestiture process "fair, equitable and impartial to all bidders" as is
required by line 1155 of the Settlement Agreement.

     Further, by letter dated February 23, 2000 to the Commission's Acting
Secretary, PSNH committed to treat Consolidated Edison and the so-called "NU
bid team" as it would any other prospective buyer of the Company's generating
assets in accordance with the proposed code of conduct governing the asset
divestiture process.  In addition, we will examine Consolidated Edison's
status in the asset divestiture process during our proceedings in Docket DE
00-009.

     Although it has been suggested that PUC staff should conduct the sale of
PSNH's generating assets, the Settlement Agreement contemplates that PSNH
will have this primary responsibility.  The PUC staff will have significant
involvement through performance of its oversight function on behalf of the
Commission.  See Settlement Agreement at 39.  The Settlement Agreement
further recognizes that the Commission will have the ultimate authority to
approve any fossil/hydro asset sales.  See Ph. II, Tr. Day XVIII, at 212-213
(PSNH construes the Settlement Agreement as giving the Commission "broad
discretion in what form of oversight...to exercise" in the divestiture
process, including the right to "approve the divestiture and actual sale.")

     In light of the foregoing, the Commission does not find it necessary for
PUC staff to conduct the asset sales.  The Settlement Agreement, as well as
the testimony of PSNH's witness on this point provide the Commission with
ample authority to be as involved with the divestiture process as determined
to be appropriate.  See Settlement Agreement, at 41:1164-1167.

     To assist us with this function, the Commission reserves the right to
hire an independent consultant to advise it in its oversight role and note
that under the Settlement Agreement, PSNH has budgeted $350,000 for that
purpose and reserved the right to request an increase in the delivery charge
if that amount is insufficient.  See Settlement Agreement, at 16.  Further,
we accept PSNH witness Long's testimony that in conducting the asset sale, it
is the Company's intent "to get the highest price [it] can" when selling the
assets, and we therefore find unpersuasive the argument that in order to
maximize the value of the proceeds from the asset sale it is necessary for
the Commission to hire a consultant to conduct the divestiture.  Id. at 213.

2.   Timing Of Asset Divestiture, Separate Fossil And Hydro Auctions And
Linking Asset Bids To Bids For Transition Service

     The Settlement Agreement, at page 39, provides that: PSNH will commence
the auction of its fossil/hydro generation assets (except for the White Lake
Combustion Turbine and potentially PSNH's ownership interest in Wyman Unit 4)
no later than 30 days after the date of the Commission's order approving the
Settlement Agreement;  NAEC's divestiture of its ownership share of Seabrook
will occur no later than December 31, 2003; and PSNH will sell all of its
ownership entitlements related to Hydro Quebec.  (The Commission's analysis
concerning the divestiture of Seabrook and Hydro Quebec assets is set forth
elsewhere in this Order.)  The Settlement Agreement recognizes the likelihood
that PSNH's generation assets will not be sold before the date on which
customers are free to choose their electricity supplier, and addresses the
issue by stating that during this time lag, PSNH "will" sell into the
marketplace the power produced by its generators and received under its power
agreements.  Settlement Agreement at 39 and 51-53.  During Phase II of the
proceedings, Mr. Long and GOECS witness Schachter indicated their willingness
to permit PSNH to use its existing resource portfolio to supply Transition
Service until such time as the assets are divested, rather than to compel
market sales as contemplated by the Settlement Agreement.  See, Ph. II, Ex.
180.  (The Commission has approved this option of having PSNH supply
Transition Service through its existing generation portfolio until such time
as its generation assets are divested in Section V (I)(4) of this Order.)
However, PSNH's proposal, as set forth in Phase II, Exhibit 180, goes beyond
merely authorizing the use of its generation assets for Transition Service.
The proposal modifies the Settlement Agreement to address several areas of
concern to many parties.  First, as noted above, it proposes a higher price
for Transition Service, which it claims would reduce deferrals collected in
Part 3 stranded costs, and which may have the effect of promoting a more
competitive generation market.  PSNH alternatively suggests a post-
divestiture option for transition pricing that is the average of the prices
administratively set by the Commission and those prices that actually result
from the bidding on Transition Service.

     Second, the divestiture could be divided into separate fossil and hydro
sales in order to accommodate the timing needs of municipalities that may
wish to bid on hydro assets.  The fossil sales would occur first; the hydro
sales could be delayed for up to one year following "Competition Day" to
enable municipalities to obtain necessary approvals in accordance with
applicable statutes.

     Third, bidders on PSNH's generating assets would have the opportunity to
link their bids with proposals for providing Transition Service in accordance
with the Settlement Agreement.       Lastly, the Settlement Agreement's
provisions for Default Service, Recovery End Date and Special Contract
Customers would not change.  The changes in Transition Service pricing
offered as an alternative by PSNH would reduce the initial overall 18.3
percent rate reduction contemplated by the Settlement Agreement.  We find
that portions of this proposal are meritorious and will accept them as
follows:

     The price of Transition Service will be established as set forth in
Section VIII (I) of this Order, for the reasons stated therein.

     The divestiture of PSNH's fossil assets will be separated from the sale
of its hydro assets, with the divestiture of the fossil assets occurring
first and the sale of the hydro assets occurring between six months and one
year following "Competition Day" to accommodate the special timing needs of
municipalities as set forth in Section VIII (M) of this Order.

     On the question of linked bids, GOECS and the BIA have suggested that
permitting bidders for PSNH's assets to link those bids with bids for
Transition Service creates the opportunity to maximize value for customers.
See Joint Brief of GOECS and Settling Staff at 40. While this suggestion
could prove to be true in certain situations, the Commission finds the
arguments favoring the linkage of Transition Service bids with those for
generation assets to be outweighed by the compelling need to create bidding
processes that produce unquestionably fair results.  Bidders and customers
must be assured that prices paid for each product result from equitable,
unbiased processes that are uncomplicated by the intricacies associated with
evaluating a seemingly attractive bid for one product that is linked to a
less than attractive bid for the other product.

     In addition, bid linkage creates difficulties that translate into added
expenses (for bidders as well as for the administrators of the asset sale and
the purchase of Transition Service), especially if linked bidders are
compelled to contemporaneously submit separate bids for each product.  This
process is further complicated by the fact that PSNH's affiliate, Select
Energy, intends to bid on Transition Service.  Accordingly, the Commission
will not accept the proposal for linked bids.

3.   Details Of Fossil Auction

     The terms of the Settlement Agreement found at lines 1126 to 1137 are
generally acceptable, though they do not specify that bidders will be
provided with the list of requirements that PSNH will impose on purchasers of
its generating assets, as set forth in the pre-filed testimony of Witnesses
MacDonald and Large.  See Ex. 10, at 14-18.  In the interest of full
disclosure and expediency, it is necessary to provide bidders with all
relevant information as early as  possible. Accordingly, PSNH shall inform
all bidders of the "Key Terms of Sale" as detailed in the MacDonald/Large
pre-filed testimony in Phase I.  Id.

     The issue of whether the Settlement Agreement adequately protected PSNH
employees post divestiture received considerable attention during these
proceedings.  By letter dated February 10, 2000 to the Commission's Acting
Secretary, the International Brotherhood of Electrical Workers Local 1837 and
the AFL-CIO stated their acceptance of the Settlement Agreement.  In light of
this development, and because the Commission finds the provisions of the
Settlement Agreement concerning employee protections to be in the public
interest, it is unnecessary to modify those provisions of the Settlement
Agreement.  PSNH shall inform all bidders of the employee protection
conditions as early as possible.

     We address specific Hydro Auction issues separately in Section VIII (M)
of this Order.

4.   Divestiture And Market Power Considerations

     The OCA, through the testimony of Dr. Richard Rosen, argues that the
acquisition of all or parts of PSNH assets by market participants who own
significant amounts and types of generating capacity in New England could
give such participants greater market power, and in turn lead to higher
prices for New Hampshire customers.  Dr. Rosen warned that such participants
would be willing to bid a higher price for the assets, knowing that they
could recoup this premium over time through their exercise of market power.
In such a case, the provision of the Settlement Agreement requiring that
proceeds of the sales be maximized would be met, but over time PSNH customers
would experience a net loss.

     Dr. Rosen suggests that the Settlement Agreement recognize the need to
balance the objectives of maximizing the proceeds from sales on the one hand,
and minimizing the impact of market power on New Hampshire customers on the
other.  To ensure that the net public benefit is the standard for accepting
or rejecting a bid, Dr. Rosen suggests that the Commission undertake computer
simulation modeling of the direct impact on wholesale market prices payable
by New Hampshire customers as part of the bid review process.

     It is possible, although by no means a foregone conclusion, that the
high bidder will, by purchasing PSNH generating assets, obtain the ability to
manipulate wholesale prices to the detriment of New Hampshire consumers.
However, to consider this possible risk, it is not necessary to require that
the Settlement Agreement be amended.  The Commission does not read the
Settlement Agreement as requiring that the Commission approve the results of
an asset sale based on the highest dollar price offered alone.

     Further, while we do not rule out use of a computer simulation model to
identify potential market power problems with various purchases, we do not
find today that such modeling necessarily should be conducted.  There are
competing concerns in the running of a successful sale, including the need to
provide transparency and clarity to potential bidders as to the basis for
selection of the winning bidder(s).  Further, as Ms. Schachter points out in
her testimony, the Commission must consider the limitations of a review with
respect to one set of bidders, when the firm awarded the sale is free in the
future to resell the assets, and as a practical matter it would be difficult
to assert jurisdiction over such resales.

     The Commission and its representatives will be closely involved in the
sale, and through this oversight process, will have an opportunity to
consider further whether, given these limitations on its usefulness, computer
simulation modeling can be a useful tool in reviewing potential bids.

M.   MUNICIPAL PARTICIPATION IN AUCTION AND PROCEEDS FROM SALE OF GARVINS
FALLS LAND

     Although the Settlement Agreement contains provisions (SA at 43:1216-
44:1255) that were intended to give municipalities an advance opportunity to
acquire hydro assets without going through the auction process, the municipal
intervenors in this docket claimed, for a number of reasons, that the
provisions do not give the municipalities a meaningful opportunity to pursue
acquisition.  It was argued that the Commission should have oversight
authority regarding any dispute as to purchase price to be paid by a
municipality desiring to purchase hydro facilities and that the Commission
should enforce its oversight by way of binding arbitration.  It was also
argued that PSNH's retention of the discretion to reject an offer from a
municipality to purchase a hydro facility left too much power in PSNH.
Others did not think towns should be limited to only purchasing facilities
within their town borders.  There were also questions about limiting
municipalities' participation in the second round of bidding under Sections
VIII (B) and (E) of the Settlement Agreement, and about the need for
mandatory groupings of hydro facilities in the auction process.

     Concerns were also expressed about the timing requirements under the
Settlement Agreement for obtaining necessary approvals to close on an asset
and the requirement that a proposal from a municipality could not be subject
to qualification.  Some argued that this limitation was unfair in that it
fails to recognize that municipalities must make offers subject to the
qualification that they obtain voter approval for an asset purchase at a
special meeting.  Others had argued that the while the municipalities should
be given sufficient time to participate given the constraints of RSA 38, they
should only expect to acquire hydro facilities at market prices determined
through a competitive bidding process.

     Some municipalities were concerned about the requirement that a
municipal purchaser of an asset must grant the same employment protections
and benefits as PSNH is proposing to establish in the fossil/hydro auction;
the critics of this provision said that it only makes sense if the assets are
grouped or sold as a whole.

     PSNH proposed during the hearings that the sale of the hydro assets be
separated from the sale of the fossil assets and that the hydro sale be
delayed for six to twelve months to allow for an opportunity to work out
better time lines for the municipalities.  Ph. II, Tr. Day XVIII, at 216 -
217.  Settling Staff and GOECS concurred with this recommendation.

     A group of municipalities proposed an auction process under which a
municipality would be able to take an asset at the highest bid price.  If the
municipality decided not to take the facility at that price it would waive
its right to utilize the RSA 38 condemnation procedure for a five year
period.

     We agree with PSNH's suggestion that the sale of the fossil and hydro
facilities should be conducted separately, with the sale of the fossil assets
taking place first and the hydro assets delayed so that some of the concerns
of the municipalities can be addressed. We also agree that while the Settling
Parties may have intended to structure the pre-auction and auction processes
to accommodate the municipalities, the procedures outlined in the Agreement
do not afford the municipalities sufficient time or flexibility to
meaningfully participate in that process.  Although the procedures need to be
improved and the municipalities given more time if the process is to
work for them, the goal must still be to obtain the highest price possible
for the hydro assets so that the proceeds can be used to offset stranded
costs.  Morever, we expect that, despite timing changes to accommodate them,
the municipalities will act with all deliberate speed to ensure that the
process is conducted as expeditiously as possible, while still giving them an
opportunity to meet their statutory requirements.  Nonetheless, we believe
there is a way to accommodate many of the concerns of the municipalities and
still obtain the best price.  We also believe that it is important to address
some of the other concerns that have been expressed about the process so that
we can provide guidance to PSNH and the parties on how to conduct the pre-
auction and auction process.

     The Commission agrees with the concern expressed by the municipalities
that there should be no mandatory grouping of the hydro assets, at least not
in the first round.  We find that the first round ought to allow maximum
flexibility in the grouping of assets by bidders so that a determination can
be made after reviewing the first round bids as to how the highest price can
be obtained.

     We do not agree with the proposal to allow a municipality to take the
facility for the highest bid that is produced by the auction process in
exchange for an agreement to waive its rights under RSA 38 for a five year
period.  We believe this would have a chilling effect on the auction process.
Although the existence of RSA 38 in and of itself may also have a chilling
effect, we can not change the law and believe it best not to over-complicate
or unfairly restrict the bidding process.

     We believe that PSNH must retain the authority to reject a pre-auction
offer from a municipality for a facility.  Moreover, we do not agree with the
suggestion that there ought to be a binding arbitration process on
negotiations between PSNH and a municipality.  We note that if the pre-
auction negotiations are not successful a municipality may still participate
in the auction and submit whatever bid it deems appropriate, thereby enabling
it to ascertain whether the price that it originally offered was a fair one,
given the market value established by the bidding process.  We also do not,
however, see a good reason to limit their participation in second round bids
and therefore find this portion of the Settlement Agreement troubling.  See
SA at 40:1139-1144.  This restriction must be removed from the hydro auction
process.

     It is not appropriate to make an exception for municipal bidders to the
employee benefit provisions that PSNH has agreed to provide to its employees
upon the sale of these facilities; municipalities should be subject to the
same provisions on employee protections as other bidders and believe what
PSNH has proposed is a fair compromise with the unions.  See VII(M)(3) of
this Order.

     The Commission agrees with the municipalities that they ought to be able
to purchase facilities outside of their municipal borders.  The Commission
does not agree, however, that the municipalities should be given any special
treatment for such purchases other than to address time and flexibility
concerns as noted above.

     The City of Concord also had some specific concerns about the sale of
land at Garvins Falls.  Concord seeks to be involved in the process of
developing auction criteria for the sale of potential generation sites to
insure that the uses of the land, post auction, will not be
incompatible with the City's long-term plans for socio-economic development
and preservation of open space.  We find that it is reasonable for the City
of Concord to have input in the development of the auction criteria for this
parcel.  However, such participation shall be limited to the City's review
and comment on proposed auction criteria.

     There was also another related issue: how to treat the proceeds from the
sale of parcels of land which may have potential value as generation sites.
The Settlement Agreement (at 46:1317-1321) identifies three parcels of land.
The State Team refers to these three parcels as sites and says that one of
those sites actually includes three separate parcels, thus dividing the land
at issue into five parts.

     Under Section VIII (H) of the Settlement Agreement PSNH is to apply 50
percent of the net proceeds from the sale of the three parcels as a credit
against stranded costs.  There was a disagreement between PSNH and the State
Team about what was intended.  The State Team claims that PSNH represented
that all of the land in all three sites was below the line, when in fact two
of the three parcels in the Garvins Falls site are above the line.
Therefore, they argue, the property that is above the line, two of the three
Garvins Falls parcels, should be treated in accordance with the usual rules
for the disposition of above-the-line property and thus ratepayers should see
100 percent of the benefits of any such sale.  Ph. I, Tr. Day XIV, at 94-99.
The other parcel at Garvins Falls and the other two sites, according to the
State Team, should be subject to the 50/50 provision.

     PSNH maintains that there are three sites, that it does not know what
the State Team was assuming when it entered into the Settlement Agreement but
the Agreement is clear that the net proceeds from the sale of all of the
sites should be split 50/50.  PSNH went on to say, however, that this was not
a major financial issue for them.  Ph. II, Tr. Day XIX, at 26.

     Given the apparent miscommunication between the parties to the
Settlement Agreement concerning this issue, the simplest way to resolve this
is to require that any parcels of land at the three sites that are below the
line should be subject to the 50/50 sharing of the amount by which the net
proceeds exceed the net book value and for any parcels that are above the
line 100 percent of the net proceeds from the sale of those parcels should be
used as a credit against stranded costs. We therefore will require a change
to the Settlement Agreement to reflect this resolution of the disagreement
among the Settling Parties on this issue.

     There is one last issue related to the municipal participation in the
auction process:  On Day XIX of the Phase II hearings, the City of Manchester
sought to introduce three exhibits - marked as Exhibit Nos. 195, 196 (both
confidential) and 197 - all related to the value of Amoskeag Hydro Station.
These were responses to data requests from a prior proceeding. The Commission
had taken the issue of their admissibility under advisement.  Upon due
consideration, the Commission has determined that they are irrelevant to this
proceeding, will not be made a part of the record, and will be returned to
the City of Manchester.

N.   NUCLEAR DECOMMISSIONING

1.   Collection Of PSNH's Seabrook Decommissioning Responsibility

     The Settlement Agreement provides (SA at 50:1435) that subsequent to the
sale of Seabrook, PSNH shall continue to be responsible for funding NAEC's
former ownership share of decommissioning liability.  This obligation is
based on full funding by December 31, 2015, using an estimated
decommissioning date of 2015 or such other date as determined by the Nuclear
Decommissioning Finance Committee (NDFC).  PSNH's customers will not have any
responsibility for increases in decommissioning funding above the amount
calculated based upon the funding schedule as of the sale date.  The risk of
any increases or decreases from the funding schedule for decommissioning
costs in existence as of the time of divestiture would be assumed by the new
owner.  Ph. I, Tr. Day II, at 56.  This means that the new owner would get to
keep what is left in the fund if the costs of decommissioning go down, but
would also be liable if costs go up. This also means that PSNH customers
would continue to pay into the decommissioning fund after divestiture of
Seabrook at the same level that they are paying as of the date of
divestiture.  SA at 50:1440.

     The proposal to allow the new owner to retain the residual of the fund
that is not needed to decommission the plant is inconsistent with the
provisions of RSA 162-F:20, II.  This statute requires that any amounts in
the fund in excess of what is required to decommission the plant "shall be
returned to the owner or owners required to make deposit in such fund and
shall cause an adjustment of the rates paid by the utility's customers."
Although the statute was enacted at a time when it was anticipated that an
integrated utility would be the owner of the plant, the clear intent of this
language is to return a fund's overcollection to ratepayers.  In response to
a record request (Ph. I, Ex. 23) PSNH states that it believes that the
Settlement Agreement "may be interpreted in a manner that is consistent with
the statute."  PSNH customers will be entitled to a refund, through
appropriate mechanisms, of any overpayments from PSNH's customers which
result from "decommissioning costs paid via present 'bundled' rates or via
future 'unbundled' SCRC charges."  Id.  Overpayments made by a new owner
subsequent to divestiture would be returned to the owner.

     PSNH's clarification in Exhibit 23 of the Nuclear Decommissioning
provisions of the Settlement Agreement differs from the testimony initially
offered during the hearing.  This clarification is acceptable to the
Commission, as long as ratepayer contributions to the fund and any earnings
related to those contributions could be segregated, and the refund of the
contributions in excess of need could be assured.  PSNH is required, at a
reasonable amount of time prior to the sale of Seabrook, to provide the
Commission an explanation of how it will assure that such "an appropriate
mechanism" will be in place.

     A related decommissioning issue is whether PSNH ratepayers' contribution
to decommissioning through a surcharge on their rates will be permanently
fixed at the level in place when Seabrook is sold.  The Settlement Agreement
(at 50:1433-1443), testimony offered during the hearing, as well as the
response embodied in Exhibit 23 appear to indicate that this is the case.

     If, during the period when ratepayers are contributing to the
decommissioning fund, the estimate to decommission Seabrook established by
the NDFC is reduced below the level established as of the date the facility
is sold, ratepayer contributions will be in excess of need.  This could
happen for a number of reasons, such as the development of less expensive or
more efficient technologies used in the decommissioning process.

     The Commission does not find it acceptable to freeze the decommissioning
surcharge for PSNH ratepayers at the level in existence as of the date of a
sale of Seabrook, thereby obligating them to pay at the level in existence at
the time of the sale of the plant even if the estimate were to go down after
the plant is sold.  While capping decommissioning payments is appropriate,
the surcharge to ratepayers must be adjusted downward in the event that the
estimate of decommissioning costs on which the surcharge is currently based
decreases after the sale of the facility, but before the facility is shut
down.  This would also mean that the decommissioning surcharge could later be
increased again if the estimate was revised upward.  In no event, however,
could the surcharge exceed the cap, which would be the amount of the
surcharge as of the date that Seabrook is sold.  The Commission, therefore,
makes this a condition of approval of the Settlement to the extent that the
Settlement could be otherwise interpreted.

     The Commission finds that the other provisions of the Settlement
Agreement concerning decommissioning related to Millstone 3 and Vermont
Yankee are consistent with industry practice and acceptable as proposed.

2.   Great Bay's Seabrook Decommissioning Proposal

     Great Bay Power, a non-utility Joint Owner of Seabrook, has argued that
the Settlement Agreement creates an "unlevel playing field" by converting a
utility's going-forward expense of paying for decommissioning into a stranded
cost.  Under the Settlement Agreement, a purchaser of NAEC's Seabrook
interest will only be liable for decommissioning costs if they increase over
the current estimates.  According to Great Bay, this gives the new owner a
competitive advantage over non-utility owners who did not purchase their
interest under such arrangements.

     We are not persuaded that it is either appropriate or necessary to
require all ratepayers to fund all or a portion of Great Bay's
decommissioning obligation.  Great Bay voluntarily entered the business as an
exempt wholesale generator responsible for its own decommissioning costs.
Since that time, the standard practice for companies divesting nuclear
ownership under restructuring has been the retention of decommissioning
obligations.  The Commission cannot level the playing field for all nuclear
plants that are sold in New England, nor can it equalize operating costs for
fossil or gas fired plants.  We think it would be impossible to find a way to
"level" the playing field; virtually any solution provides advantages or
disadvantages for some participants over others. The Settlement Agreement's
proposal for funding decommissioning, subject to the changes discussed above,
is reasonable.  We note further that the Commission's authority under RSA
162-F:19,III to permit the collection of a decommissioning charge is limited
to utilities. Although there is no definition of "utility" in Chapter 162-F,
Great Bay is not a "public utility" as defined in RSA 362:4-c, I.  Therefore,
the Commission believes that it does not have jurisdiction to grant the
relief requested, and we deny Great Bay's request and approve this portion of
the Settlement Agreement consistent with our discussion above.

O.   RATE DESIGN

1.   Overview

     The Settlement Agreement proposes certain basic parameters for rate
design, and a small number of specific provisions for certain situations.
PSNH, on its own initiative,  proposed specific tariffs to implement the
Settlement Agreement, including particular rate proposals that were neither
required nor barred by the Settlement Agreement.

     The only rate design parameters to which the Settling Parties are
committed are those set forth in the Settlement Agreement at 12:331-13:360.
As characterized by the State Team, the key items in that commitment are:

     Ensuring that the residential class receives the same rate reduction as
all other classes.

     No cost shifting between the residential class and other classes.

     Equal per kilowatt hour charges for all classes for the Systems Benefits
Charge, the Energy Consumption Tax and Transition Service.

     No customer to receive a higher bill after restructuring.

     Elimination of the "humped" design in the residential rate in exchange
for more appropriate targeting by the company of low-income assistance and
energy efficiency.

     The Company notes as well that the Settlement Agreement provides for
lower or no rate reduction for certain optional classes, the closing of
certain economic development rates, and the requirement that changes to the
Company's proposed rate design be made on a revenue-neutral basis.

     Many of the numerous rate design particulars included by the Company in
its proposed tariffs went undiscussed during the hearings, and others were
noted but drew little attention. However, certain portions of the Company's
proposal raised issues that have sparked a great deal of discussion among
several parties.  These include the class-specific SCRC and the failure to
lock in the SCRC rate design for the period after the 30 month IDCP expires,
issues that are discussed elsewhere in this Order.  PSNH's proposal to impose
certain new or increased fees and the $0.028 per kWh delivery service rate
for special contract customers will be discussed below.

2.   Specific Rate Calculations - First Year

     The Agreement specifies an initial fixed average percentage rate
reduction for PSNH's customers served on standard tariff rates.

     The first step in the Company's specific rate calculations was the
calculation of the class revenue targets.  The Company calculated the revenue
target for the residential and outdoor lighting classes, and for the general
service classes combined, by decreasing current rate revenue for each class,
or group of classes, by the target percentage reduction.

     The Company based its rate design calculations on billed kWh sales and
current revenue by class for the test year ended September 1998, as
proformed.  The average rate level for all customers taking service on PSNH's
standard tariff rates is currently $0.1297 per kWh.  PSNH calculated the
overall Company revenue target by multiplying billed kWh sales for the test
year by the target average total rate for the Company.

     Given the Transition Service rate and SCRC initially proposed in the
Settlement Agreement, the average rate would be $0.10595 per kWh.  A rate
reduction from $0.12970 per kWh to $0.10595 per kWh would be an average
reduction of 18.3 percent.  Thus, the overall revenue target and associated
target percentage reduction are developed using whatever initial overall rate
level falls out upon adjustments to any of the components of the overall
rate.

     Under the Settlement Agreement, each class of customers will be charged
an equal cents per kWh amount for the System Benefits Charge ($0.0025 per
kWh), Consumption Tax ($0.00055 per kWh), and Transition Service energy
($0.037 per kWh for Year One under the original proposal, and $0.040 per kWh
pursuant to this Order).  This means that, on average, $0.04005 per kWh for
these amounts combined, per the original proposal, had to be recovered from
each class, assuming customers use Transition Service.  Given the
Commission's determination that Transition Service must be set at $0.040 per
kWh for the first year (3 mils higher than the original Transition Service
proposal), the amount per kWh that will have to be collected from each class
for these amounts combined will be $0.04305 per kWh.

     In PSNH's rate design, for each class, $0.04005 per kWh was subtracted
from the overall cents per kWh target.  PSNH then had to allocate this
difference between the Delivery Charge and SCRC components.  According to
PSNH, this was done in a manner that attempted to provide a reasonable
recovery of delivery costs from each class, and that accomplished the overall
average Delivery Charge of $0.028 per kWh and average SCRC of $0.0379 per
kWh, as required by the Agreement.

     PSNH then calculated the total, bundled rates that were required to
accomplish the Agreement's other rate design and revenue objectives.  Since
under PSNH's proposal certain rates received a smaller decrease than the
target percentage reduction for the class, the standard rates were reduced by
a very small additional amount to achieve the overall target percentage
reduction for the class.  In all cases, each rate included at least a minimum
2 mil per kWh energy charge, to avoid a zero or negative energy charge that
might have been produced had the residual SCRC pricing been rigidly applied
to the rate levels.  In the general service classes, adjustments were made to
the energy or demand component of the delivery charge, by amounts necessary
in the particular case to resolve the transition problem between the rates
for each class, as described below.

     For Outdoor Lighting Delivery Service Rate OL, and Energy Efficient
Outdoor Lighting Delivery Service Rate EOL, PSNH first calculated the total,
bundled rates required to accomplish the target percentage decrease for these
classes.  In order to accomplish this, the current rate for each type and
size of light was reduced by the target percentage reduction.  The rate
structure for Rates OL and EOL consists of a monthly Delivery Charge which is
billed on a "per luminaire" basis and which is the same each month.  The
other charges (System Benefits Charge, Consumption Tax, SCRC, and Transition
Service energy charge) are all kWh charges which would be multiplied by the
corresponding monthly billing kWh shown in the tariff.  In order to unbundle
the rate for each type and size of light, the System Benefits, Consumption
Tax and Transition Service energy charges were established at the cents per
kWh amounts required by the Agreement, and the SCRC was established at the
$0.0379 per kWh target amount for the class.  The Delivery Charges were
calculated by subtracting from the bundled rates the product of each cents
per kWh charge and the average monthly kWh use for each type and size of
light.

     Since the kWh usage for each light would now vary month to month, the
total amounts billed for each of the kWh charges would also vary month to
month.  However, by using the average monthly kWh use in order to back into
the Delivery Charges, the result is that all bills would be reduced by the
target percentage reduction, over a twelve-month period.

     As modeled by the Company, and based on the Transition Service rates as
proposed initially by the signatories, the average retail rate for a customer
taking Transition Service during the first year following Competition Day
would be $0.106 per kWh.  The Year One $0.106 per kWh is comprised of various
components as shown in the table below.

     A similar breakout is shown below for Year One, reflecting the increased
Transition Service charge required by this Order, and the decreased SCRC
estimated in this Order:


Rate Component

Transition Service Charge
First Year,Per Settlement Cents per kWh
3.700
First Year, Per Order Cents per kWh
4.000

Delivery Charge
First Year,Per Settlement Cents per kWh
2.800
First Year, Per Order Cents per kWh
2.800

Stranded Cost Recovery Charge
First Year,Per Settlement Cents per kWh
3.790
First Year, Per Order Cents per kWh
3.400

System Benefits Charge
First Year,Per Settlement Cents per kWh
0.250
First Year, Per Order Cents per kWh
0.250

Consumption Tax
First Year,Per Settlement Cents per kWh
0.055
First Year, Per Order Cents per kWh
0.055

Estimated HQ Recovery (FN 27)
First Year,Per Settlement Cents per kWh
na
First Year, Per Order Cents per kWh
0.100

TOTAL
First Year,Per Settlement Cents per kWh
10.595
First Year, Per Order Cents per kWh
10.605

3.   Specific Rate Design Proposals

a.   Delivery Service Tariff - Overall Structure

     The proposed Delivery Service Tariff is a compilation of applicable
provisions of PSNH's existing Tariff for Electric Service (the full
requirements tariff) and PSNH's Tariff for Delivery Service No. 1 (the tariff
for the Retail Competition Pilot Program).  The proposed Delivery Service
Tariff will supersede both of those tariffs.

     The Delivery Service Tariff contains terms and conditions for delivery,
terms and conditions for energy service providers (competitive suppliers of
electricity), delivery service rate schedules for the various classes of
service, and two energy service rate schedules (for Transition Service and
Default Service).

     The Delivery Service Tariff was drafted to be consistent with the
Agreement and to be consistent with Commission Orders in the restructuring
docket (DR 96-150) for those aspects and provisions of the Delivery Service
Tariff that were not addressed in the Agreement.  The Commission finds that
the overall structure of the Delivery Service tariff is appropriate and
approves it.  However, PSNH's additional proposed changes to certain language
and provisions will be addressed in more detail below.

b.   Delivery Service Tariff - Recovery Of Costs

     As shown on Ph. I, Ex. 13, the delivery service tariff provides for the
following delivery charges, on average, by class:

Class
Residential
Average delivery charge
3.731

Class
General Service
Average delivery charge
2.819

Class
Primary General Service
Average delivery charge
1.424

Class
Large General Service
Average delivery charge
1.166

Class
Overall Average
Average delivery charge
2.8

     Other than the call for unbundling transmission charges from
distribution charges, none of the parties objected to PSNH's proposed design
for the basic Delivery Service charge.

Witnesses for both BIA and OCA testified that the energy, demand and customer
charges designed by PSNH to recover the basic delivery costs were acceptable,
despite concerns each of these parties had with the 2.8 cent average overall
level of such charges.  In particular, OCA witness Dr. John Stutz testified
that the Delivery Service charges were generally consistent with charges that
would be developed by allocating the underlying transmission and distribution
charges.  The Commission approves the delivery service rate schedules filed
by the Company, but notes that those schedules are likely to change slightly
to reflect the recovery of the HQ transmission support payments, as discussed
in Section VIII (F)(4) above.  We further approve the request of GOECS that
we require the tariff to cite that the Settlement Agreement controls in the
case of a difference between the two.

c.   Delivery Service Tariff - Changes Allowed Or Required By Proposed
Agreement

     Messrs. Long and Hall testified that the Agreement specifically provide
for the following three rate design changes: (1) flat residential cents per
kWh rates, (2) adjustment for transition between General Service rates, and
(3) partial or no reduction to certain optional rates.  We take each of these
up in order below.

(1)  Flat Residential Cents Per kWh Rates

     First, we approve the Settlement Agreement's proposal to eliminate the
so-called "humped" rate design for residential rates.  As part of its
findings in Docket No. DR 80-260, the Commission required all New Hampshire
electric utilities to adopted a "humped" rate design for residential rates.
Under that rate design, the energy charges were blocked with the first 250
kWh discounted.  The rationale for the discount on low use was that low-
income customers tended to use lower amounts of electricity.  The energy
charge for the next 550 kWh was increased to recover the discount applied to
the first 250 kWh, and the "all additional" kWh were priced to recover the
remaining revenue requirements.

     Save Our Homes Organization urges the retention of this rate design,
arguing that there is a high correlation between disproportionately low usage
and lower incomes.  Because the Commission has approved a statewide EAP
program for low-income customers in Docket No. DR 96-150, it is unnecessary
to retain the humped rate design.  As noted by PSNH, elimination of anomalous
rate designs are best addressed in the context of decreasing rather than
increasing rates. Thus, the occasion of this overall reduction in rates and
introduction of burden-based low-income rates is the ideal occasion to
eliminate the humped design.

     As pointed out by the signatories, EAP is designed specifically to
address the issue of unaffordable rates, and thus provides a direct
substitute for such other tools as "humped" rate designs to address
affordability issues.  In the absence of testimony suggesting a different
rate design is clearly superior for other purposes, such as efficiency, we
consider it appropriate to return to a flat cents per kWh rate for
residential customers, and we will not disturb the Agreement on this issue.

(2)   Transition Between General Service Rates

     PSNH states that the design of its existing general service rates (Rates
G, GV and LG) does not provide for a smooth transition for customers whose
loads are expanding and who therefore must transfer from Rate G to Rate GV or
from Rate GV to Rate LG.  (Rate G is available to customers whose loads do
not exceed 100 kW; Rate GV is for customers whose loads are between 100 and
1,000 kW; and Rate LG is for customers whose loads are greater than 1,000
kW.)  Under the current design, most commercial and industrial customers who
switch from Rate G to Rate GV or from Rate GV to Rate LG will realize a
higher bill for the same amount of usage around the transition points between
the respective rates, even though the overall average cents per kWh for the
Rate GV customer class is less than the Rate G class and the overall average
cents for kWh for the Rate LG class is less than the Rate GV class.

     To correct this problem, PSNH has proposed to shift some revenue among
the three general service classes.  However, the overall reduction to all
three customer classes remains the same under the Agreement, and no customers
are expected to see a higher bill after Competition Day as a result of this
rate design change.  We approve the Agreement's intention to prevent
anomalous results for customers transitioning from one general service rate
classification to the next.

(3)   Partial Or No Reduction To Certain Optional Rates

     The Agreement also specifies that there may be a lower percentage
reduction (or no reduction) to certain optional rates, because such rates are
either already discounted and/or are time-differentiated.  The Agreement does
not set out particular rates for such classes.  The reductions from current
rates proposed by the Company for such optional rate classes are shown in the
table below:

Optional Rate
Load Controlled Service
Reduction
0%

Optional Rate
Controlled Off-Peak Service
Reduction
0%

Optional Rate
Controlled Water Heating
Reduction
0%

Optional Rate
Residential Time-of-Day
Reduction
10%

Optional Rate
General Time-of Day
Reduction
10%

Optional Rate
Transitional Space Heating
Reduction
0%

     According to PSNH, because these rates are already discounted,
unbundling produces either a negative cents per kWh Delivery Charge or a
Stranded Cost Recovery Charge of less than the target amount for the class,
even before applying the overall Agreement reduction.  As a result PSNH is
proposing no additional reduction for these rates, and is proposing closing
the rates to new applications.  (The Controlled Water Heating rate is already
closed to new applications.)

     The Company states that, because it will no longer be in the generation
business, it intends to begin eliminating "generation-related" pricing
structures (e.g. time-differentiated, controlled or interruptible rates).  It
claims it is not meaningful for a delivery company to offer such
generationrelated rates, although it concedes that it may be useful in the
future for delivery companies to cooperate with suppliers in facilitating
interruptible services.  The Company also anticipates that competitive
suppliers will offer time-differentiated pricing in the future.

     As a result, PSNH wants to create an incentive for customers under
certain rate options to switch to the standard rate.  For this reason, it
proposes only a 10 percent reduction to Rate R-OTOD and to Rate G-OTOD from
the existing levels of those rates, and proposes closing the rates to new
customers.  Finally, PSNH is proposing no reduction for Transitional Space
Heating Rate TSH because this rate is already discounted.  (The separate rate
schedule for Rate TSH, or Supplement No. 2 to Tariff No. 38, has been deleted
and Rate TSH has been incorporated into the applicable main-service rate
schedules, Rate G and Rate GV).  Rate TSH remains closed to new applicants.

     The additional revenue that would be received as a result of not
applying the full discount to these rates was used to further reduce other
rates for the class.  For example, the overall average discount for the
balance of the residential power and light class would be 0.2 percent greater
than the reduction for the class on average.

     There was little discussion on the record of the Company's proposals
with regard to the optional rates.  As we discuss in the context of general
service interruptible rate N-5, the recent price spikes in the New England
market, and the underlying pressure of loads on available resources, indicate
that care should be taken before abandoning tools that can be used to achieve
economic load reductions when needed.  We note that a large portion of the
residential class is likely to take advantage of Transition Service provided
under the auspices of the Company, and to that extent the Company will
continue to have generation-related responsibilities in the near term. We
also observe that the amounts of revenue that will have to be reallocated to
the remainder of the residential class are de minimus, given the low numbers
taking service under the optional rates.

     While the Settlement Agreement allows for the possibility that some
rates would see no or more limited reductions, it does not require the
specific limitations proposed by the Company.  We are not persuaded on this
record that the time-of-use and load-controlled rates should be
treated differently from other rates, except as necessary to prevent negative
energy charges. Accordingly, we do not approve the closure of such rates at
this time, nor the intentional limitation of reductions as a tool to promote
migration off such rates.  We will, however, permit the Company to renew its
proposals during the T&D rate case anticipated to be filed shortly before the
IDCP period ends.  As with the unbundling of transmission and distribution
components of rates, at that time greater focus can be brought to bear on the
question of the proper design of T&D rates in a restructured electricity
industry.

d.   Delivery Service Tariff - Changes Neither
Required Nor Prohibited Under Proposed Agreement

     There are several other changes PSNH is proposing that are not
specifically addressed in the Agreement.  These changes are discussed below.

(1)   Elimination Of Elderly Discount

     The Company proposes to terminate the Elderly Customer Discount one year
after Competition Day.  The Elderly Customer Discount was implemented in
1972, when Construction Work in Progress (CWIP) was included in PSNH's rate
base.  The reason for the discount was the assumption that elderly customers
would not live long enough to receive the full benefits of Seabrook and
therefore should not have to pay for the cost of construction.  In 1979, the
so-called "anti-CWIP" law was enacted, and CWIP was removed from PSNH's
rates.  At that time, the discount was closed to any new customers, but
existing customers who were at least 70 years of age could still receive the
discount.  With the double-digit overall rate reduction and the introduction
of a statewide Energy Assistance Program (EAP), the Company argues that it is
no longer necessary to provide an elderly customer discount.  To avoid the
hardship this proposal may cause for some elderly customers, PSNH is
proposing a one year delay in terminating the discount in order to allow time
to identify those elderly customers who are eligible for the statewide EAP.

     OCA opposes the elimination of the Elderly Discount but is "willing to
discuss eligibility transfer criteria."  On behalf of GOECS, Ms. Schachter
recommended that the issue be deferred and explored in a separate hearing,
and no party objected.  Ph. II, Ex. 164, at 10. This issue has received very
little attention, and is certainly deserving of review in a separate
proceeding in which all interested parties would have an opportunity to
participate.

     SOHO/CAP point out that, of the customers receiving service under the
discounted rate, approximately half are between 80 and 90 years old, and half
are at least 90 years of age. Responding to PSNH's suggestion that low-income
customers in this rate class can enroll in the energy assistance program,
SOHO/CAP express concern about what they characterize as senior citizens'
reluctance to enroll in what they perceive to be a public assistance program.

     Currently, there are fewer than 3,000 customers who are receiving the
Elderly Customer Discount.  They are all of advanced age, and have been
receiving this same rate since the 1970's. Given the small number of
customers taking service under this rate, and their advanced ages, any
efficiency that might arguably be achieved by eliminating this rate and
requiring income-eligible customers to move to the EAP is outweighed by the
dislocation and disruption such a change would necessitate.  This is not to
say that eligible customers whether on this rate or any other should not be
encouraged to switch to the EAP.  Accordingly, we agree with the Company's
suggestion to provide outreach to such customers through the Community Action
Agencies and otherwise, to advise them of the availability of EAP, and assist
them in moving to the EAP if they qualify.  Further, the Company may bring
this question forward again in its next general rate case, at which time it
will have further detailed information on the aggregate members of the class.

(2)   Elimination Of Targeted Lifeline Rate

     The Company proposes to eliminate Targeted Lifeline Rate D-TL.  Because
of the introduction of a statewide EAP, PSNH argues that the Residential
Service Targeted Lifeline Rate D-TL Pilot Program is no longer necessary.
This rate was closed to new customers in 1984. There are about 150 customers
under this rate.  In order to provide a smooth transition, PSNH will provide
a list of the customers served under Rate D-TL to the respective CAP agencies
prior to Competition Day in addition to providing advance customer notice of
the rate's termination and of the statewide EAP.  We approve the Company's
proposal.  As we stated in the context of the "humped" residential rate, the
EAP we have previously approved, and which we affirm today, should provide
the necessary "affordability" protection for the customers targeted by the
Lifeline rate.

(3)   Unbundling Outdoor Lighting Rates Using Actual Monthly Usage

     The Company proposes to unbundle outdoor lighting rates using actual
monthly kWh. Outdoor lighting rates are unmetered rates, and the energy
component of each rate is based on estimated monthly kWh usage.
Historically, PSNH has included energy charges in its outdoor lighting
prices by assuming that the energy usage would be the same in each of the
twelve months of the year.  In the past, the Company determined estimated
energy usage for each luminaire by estimating the annual amount of "burn"
hours, multiplying that number by the wattage of each luminaire and dividing
the result by twelve.  This process was acceptable in a "bundled" framework
where PSNH was providing the energy for the luminaire.

     Because the generation component is now unbundled and will be supplied
competitively, PSNH is proposing to utilize the actual monthly kWh usage for
each of the lighting fixtures, taking into account the variation in the
number of hours of darkness by month.  As a result, customers will see
seasonal variation in their bill amounts, higher in the winter and lower in
the summer, because of the variation in the monthly usage. On an annual
basis, this customer class will realize the full average percentage reduction
to rates.

     In its determination of actual monthly kilowatt-hours (kWh) for each
fixture, PSNH referred to the Farmer's Almanac to determine the number of
operating (or night-time) hours for each calendar month for New Hampshire.
This provided 4,345 hours of operation annually.  The current amount of
kilowatt-hours are based on 4,000 hours.  As a result, annual kilowatt-hours
for the outdoor lighting class increased by 2,200,000 kWhs.  PSNH adjusted
its test year kWhs accordingly for rate calculation purposes.  We accept the
Company's proposal.  It better tracks cost causation, and the Company's basis
for estimating seasonal usage is appropriate.

(4)   Elimination of NEPOOL Type 5 Interruptible Service Rate

     As in the case of optional residential load control rates, the Company
proposes the elimination of Rate N-5, NEPOOL Type 5 Interruptible Service
Rate.  Currently there are no customers under N-5.  The NEPOOL members in the
past voted to offer little or no payment for customer interruptions during
periods when NEPOOL implements Action 10 under its Operating Procedures No.
4.  As a result, there was no monetary incentive for customers to take
service under Rate N-5.  Because of this, and because of the reasons cited
above for elimination of interruptible rates, PSNH proposed to eliminate the
rate.  However, in the event that NEPOOL changed its current policy and
developed a regional interruptible rate policy which is beneficial to PSNH's
customers, PSNH stated that it might later file a new interruptible rate
schedule that conforms to the new NEPOOL policy.

     Last summer supplies were tight against unexpectedly high demand.  The
region suffered price spikes, and several states including New Hampshire cut
back substantially on electricity use to avert potential brown-outs and
worse.  Anticipated supply had not yet come on line, the economy was
expanding, and the weather in June was as hot as the typical August, catching
plant operators with their generators down for routine pre-summer
maintenance.

     In light of the need to allow customers to choose interruption as a
demand-side option to meet reliability needs, now is not the time to
eliminate load curtailment rates.  Rather, the Company should examine the
reasons why no customers are presently taking service on this rate, and the
proposed wholesale tariff options being developed at the ISO-NE level to
provide options for compensating end users for voluntary load curtailment.
Based on these developments, the Company should develop an updated
Interruptible Service tariff, and file it with the Commission, in time to be
useful in helping address this summer's peak, with a proposal for any
improvements to N-5 that will enhance its usefulness as a reliability tool.

(5)   Closure Of ED, BR And LR Rates

     The Company also proposes to close Economic Development Service Rate ED,
Business Retention Service Rate BR and Load Retention Service Rate LR.  PSNH
is proposing to close these rates for two reasons.  First, the Agreement's
rate reduction to the standard rates reduces the price differential between
standard rates and these rates.  Customers served under these rates will
receive a lower percentage discount or no discount at all.  As a result of
the reduction to PSNH's standard rates, the need for lower priced rates to
attract or retain load is reduced.  Second, in accordance with NH RSA 378:11-
a, V, these rates will terminate on December 31, 2002, less than three years
after Competition Day.  It is unlikely that discounted rates that will be in
effect for only three more years, and that are priced close to the standard
rates, will be necessary to retain or attract load.  For the reasons stated
by the Company, we approve the Company's proposal regarding closing rates ED,
BR and LR.

e.   Unbundling Of Transmission And Distribution Rates

     The Settlement Agreement's proposed average delivery service charge of
$0.028 per kWh, varies by class of customers and includes both transmission
and delivery (T&D) service.  Freedom argues that PSNH's proposed bundling of
T&D is inconsistent with the policy of open-access transmission tariffs
previously articulated by the Commission and that a customer will be
forced to pay for distribution charges even though the customer may only be
using the transmission system.  Freedom requests that the Commission should
require the same unbundling of transmission for PSNH as was done for Granite
State Electric Company (GSEC) in Docket DR 98-012.

     PSNH maintains that the data necessary to calculate separate T&D service
charges is not currently available and avers that the attempt to unbundle T&D
rates is ultimately an attempt to avoid paying stranded cost recovery
charges.  Great Bay Power argues that RSA 374-F requires PSNH to unbundle
within an established timeframe prior to the anticipated rate proceeding.
The State Team argues that RSA 374-F:4 only requires unbundling of T&D "at
the earliest practical date," that FERC has determined it unnecessary to
unbundle T&D, and that no customer is in a position to benefit by having
separate rates.  According to the State Team, unbundling is premature and the
necessary data is unavailable.  It urges the Commission to wait until the
rate case for the new delivery company, i.e, 30 months down the road, before
considering the unbundling of T&D.  The State Team distinguishes PSNH from
GSEC, which had a separate transmission affiliate and therefore had separate
cost data available to it. It is argued that PSNH, as an integrated company,
does not have this data available.

     The Commission is not persuaded to require PSNH to unbundle T&D at this
time, but will reserve the right to reconsider this issue at such time we
deem appropriate.  PSNH's situation is different from that of GSEC and we
note the absence in this record of reliable cost data that would allow for an
accurate unbundling.  We also think it important to consider where FERC
currently stands on this issue, and we would need a more thorough review
before we could make that determination.  On the other hand, however, we do
not want to preclude the consideration of this issue between now and the
expiration of the 30 month IDCP.

F.   Other Fees And Charges

     As part of this filing, PSNH proposed increasing and/or introducing a
residential late payment charge, new or increased service charges, and a line
extension surcharge.

(1)   Residential Late Payment Charge And New Or Increased Service Charges

     PSNH currently assesses a 1.5 percent per month late payment charge for
customers under commercial rates GV and LG.  PSNH proposes to implement late
payment charges for residential service, general service and outdoor lighting
service.  The reason given for expanding the application of the late payment
charge to the other customer classes is to encourage timely payment of bills.
Absent a late payment charge, PSNH argues, its bill is placed at a higher
risk for non-payment compared to most other utilities' bills.  Because a
significant amount of programming is required to PSNH's billing systems to
implement late payment charges for the classes that are not currently
assessed such charges, PSNH states that it would not be able to implement the
late payment charge for the residential, general and outdoor lighting classes
on Competition Day.

     PSNH proposes to update its Service Charge fees under its residential
rates as well as General Service Rate G and General Optional Time of Day Rate
G-OTOD to reflect today's costs. As part of its Service Charge provision,
PSNH is proposing a new field collection fee to encourage customers to pay
overdue bills prior to the commencement of collection action. PSNH argues
that it's Service Charges have not changed in almost 18 years, and do not
recover PSNH's cost of establishing service or reconnecting service. Below is
a table of the current and proposed Service Charges:


Service Charge Fees
Establishing Service - Live Meter
Current Tariff No. 38
$8.00
Proposed Tariff No. 2
$12.00

Service Charge Fees
Reconnecting Meter - Normal Hours
Current Tariff No. 38
$16.00
Proposed Tariff No. 2
$20.00

Service Charge Fees
Reconnecting Meter - Off Hours
Current Tariff No. 38
$32.00
Proposed Tariff No. 2
$48.00

Service Charge Fees
Field Collection
Current Tariff No. 38
None
Proposed Tariff No. 2
$16.00

     Concerning PSNH's proposals for field collection charges, late payment
charges and increase fees for connections and reconnections, SOHO/CAP believe
it is appropriate for the Commission to defer these issues to another docket.

     The State Team agrees that the question of additional end-user service
charges should be deferred to a rate design docket in connection with the
anticipated T&D rate case, after the 30 month IDCP, where they can receive
more attention.

     The question of the appropriateness of late fees and field collection
fees, and the proper level of service establishment and meter connection
fees, requires greater exploration, in a docket where these matters can
receive more concentrated focus.  Accordingly, we do not approve the new
charges or increased charges in this docket, but PSNH may renew its request
for such new and increased charges in its next overall residential rate
design filing.

(2)   Line Extensions

     PSNH is proposing to increase its surcharge for single-phase line
extensions along a public way from $0.04 per foot to $0.08  per foot, and to
increase the credit for the cost of two additional phases along a public way
from $150 to $300.  The 4 cent surcharge and the $150 credit have not been
revised for 20 years.  Since no party objected to this proposal, and in light
of the fact that the proposed rates appear just and reasonable when compared
with similar rates charged by other utilities in this state, we will accept
the Company's proposal.

g.   Terms And Conditions For Suppliers

     PSNH has also proposed to introduce a new section entitled "Terms and
Conditions for Energy Service Providers" (Terms and Conditions for
Suppliers).  This section of the Tariff is designed to address and govern the
day to day dealings primarily between the Company and a Supplier and in some
situations with the customer.

     Below is a table showing the services offered under Section 2 entitled
"Services and Schedule of Charges" and their respective charges:


Supplier Service
Customer Change of Supplier
Schedule of Charges
$ 5.00 per request (not applicable if customer is terminating Transition
Service).

Supplier Service
Customer Usage Data
Schedule of Charges
No charge for monthly billing determinants used by the Company for billing
purposes.

Supplier Service
Interval Data Services:
1.  Telemetering Interval Data Access
Schedule of Charges
$ 25.00 per current month, $ 50.00 per historic month

Interval Data Services:
2.  Load Pulses Output
Schedule of Charges
Agreed-upon price depending upon the equipment required and labor time.

Interval Data Services:
3.  Extended Metering Service
Schedule of Charges
Installed cost of equipment and any ongoing charges.

Interval Data Services:
4.  Special Requests
Schedule of Charges
Agreed upon price depending upon the equipment required and labor time.

Supplier Services:
Customer Load Analysis
Schedule of Charges
$ 60.00 per hour

Supplier Service
Customer Service
Schedule of Charges
$ 1.10 per minute

Supplier Service
Billing and Payment Service
Schedule of Charges
$ 0.50 per bill rendered
$ 100.00 minimum charge per month
$ 95.00 per hour of labor for initial programming
$ 50.00 per hour of labor for rate maintenance and error correction.

Supplier Service
Collection Service
Schedule of Charges
0.252% of total monthly receivable dollars

     Aside from a request from the New Hampshire Consumer Utilities
Cooperative to consider free or reduced service charges for public interest
aggregators, no party commented on the proposed fees.  Since these are new
services that will impose additional costs on the Company, they are proper
for recovery from suppliers taking the services.

h.   Special Contracts

     In considering the Settlement Agreement's provisions concerning Special
Contracts, we are called upon to decide three issues.  The first is whether
to approve the set of options proposed by the Settlement Agreement under
which Special Contract customers could elect whether to choose an alternative
supplier for their power.

     No party objected to the proposal to give Special Contract customers the
three options set forth in the Settlement Agreement.  Those options appear to
provide reasonable opportunities for Special Contract customers to either
secure transition service from PSNH, or to shop for alternative supply
arrangements by either unbundling their contracts or terminating them.
Accordingly, we approve the provisions of the Settlement Agreement with
respect to amendments to the terms of the Special Contracts.  While the
Company states that the terms of Special Contracts are dictated by the
contracts, those contracts are subject to the authority of the Commission.
As we stated in Order No. 23,139, February 8, 1999, the Commission "retains
jurisdiction over all contracts filed with it for its approval."  Id. at 7
(citation omitted).  As we did in Docket DR 98-139, however, we will require
the Company to present amendments to the contracts to those customers for
their acceptance, and for filing with the Commission.  We also will require
the Company to keep the Commission informed periodically as to the elections
that such Special Contract customers have made with respect to the additional
options provided as a result of the Settlement Agreement.

     With respect to the difference in revenues between those expected under
the Special Contracts and those that would be received had the customers been
billed at the tariffed rate appropriate for their usage patterns, OCA and
Great Bay assert that we cannot and should not approve the Company's proposal
that no such revenues be imputed to it, when determining the appropriate
delivery service revenue requirements of the Company.

     In the context of this complex Settlement Agreement, we will not adjust
the Company's revenue requirements for alleged shortfalls in receipts
associated with Special Contract customers during the initial delivery
service period.  During the rate case anticipated at the end of the 30-month
initial period, there will be ample opportunity to examine the extent to
which non-Special Contract customers are being put at risk of making up a
shortfall in revenues as a result of the rates being paid by such customers.
As we have stated before, approval of these amended Special Contracts does
not mean that recovery of lost revenues resulting from the discounted rates
under those contracts would be appropriate when the contracts are ultimately
considered in the context of a rate proceeding.

     With respect to the relationship between the delivery service charge and
the SCRC for Special Contract customers, our decision that Transition Service
rates must be increased by 3 mils per kWh requires that we consider further
the impacts of the Company's special contract pricing proposal. (FN 28)
There are several ways to deal with the increase.  The Special Contract rates
can be increased.  Another option would be to hold the total average special
contract rate constant, and either recover the 3 mils per kWh increase in the
Transition Service rate from other customers or require the Company to absorb
it.

     We note that, depending on which option the Special Contract customer
chooses, the Company's proposal amounts to an amendment to the Special
Contract.  We will direct the Company, if it accepts the conditions for
approval of the Settlement Agreement, to make a proposal for treatment of the
revenue and rate impacts of the increase to Transition Service rates with
respect to Special Contracts, as part of its compliance filing.

P.   OTHER MATTERS

1.   PSNH/NHEC Settlement

     The Settlement Agreement, as filed originally, modeled sales from PSNH
to NHEC, PSNH's largest wholesale customer, through June 30, 2000.
Thereafter, the model assumed PSNH received revenue associated with NHEC ski
areas served under special contracts and the demand-related charges from NHEC
consistent with the FERC's order on rehearing in the PSNH/NHEC Amended
Partial Requirements Agreement (APRA) dispute. (FN 29)  On September 30,
1999, PSNH and NHEC entered a settlement agreement  (PSNH/NHEC settlement)
which resolves all disputes concerning the APRA.

     The PSNH/NHEC settlement provides that all services from PSNH to NHEC
would terminate on January 1, 2000.  As compensation for terminating the
APRA, NHEC would make an $18 million termination payment to PSNH on or before
December 31, 1999.  PSNH and NHEC amended and restated the PSNH Interruptible
Contract (Amended Interruptible Agreement) which applies to the ski area load
served by NHEC under special contract.  Sales to NHEC's ski areas will
continue in effect for the term of their contracts as amended and the
revenues from the NHEC ski area contracts will be used as an offset to Part 3
stranded costs, if the Settlement is approved.  The Seabrook power contract
("Buyback Agreement") remains in effect until July 1, 2000.  Based on the
PSNH/NHEC settlement, PSNH will reduce the stranded asset balance by the $18
million termination payment from NHEC and write off an additional $6.2
million upon approval of the Settlement.  The new delivery revenue, estimated
to be $2 million per year, will be credited to SCRC Part 3 stranded costs
during the initial 30-month delivery period and thereafter it will be
credited to the distribution rate.

     Some parties question whether the PSNH/NHEC settlement increases
stranded costs to PSNH's customers.  Staff Advocates, after conceding the
difficulty in estimating the value to PSNH of the APRA, estimate a value due
to the loss of the APRA at either $42 million or $92 million depending upon
whether NHEC would have replaced PSNH sales with Qualifying Facilities.  Ph.
II, Ex. 104 at 51.  Others (Long/Hall and Cannata/Antonuk) believe the
PSNH/NHEC settlement provides benefits to PSNH's customers that are
comparable to, if not greater than, that expected if PSNH had remained in the
APRA and provided NHEC power under the APRA as clarified by the FERC.

     Whether the PSNH/NHEC settlement is a benefit or cost to customers
hinges on what level of power NHEC would have received over the term of the
APRA from Qualifying Facilities to replace PSNH sales.  No exact number is
possible, of course, to ascertain the loss of PSNH sales to NHEC, but the
record supports that a considerable level of QF sales were possible and
did, in fact, occur during November and December 1999.  Ph. II, Tr. Day XVII,
at 43-44.  The use of the $18 million termination payment, the write-off of
$6.2 million, and the credit of $2 million per year to Part 3 stranded costs
during the 30-month delivery service period is a fair and reasonable outcome
to the issue of whether stranded costs were mitigated by PSNH entering into
the PSNH/NHEC settlement.  The PSNH/NHEC settlement allowed NHEC to move to
retail competition on January 1, 2000, end APRA and implement a substantial
rate reduction for its customers.  By doing so, the PSNH/NHEC settlement
meets the intent of 1999 N.H. Laws Chapter 289, to have an equitable
resolution of the longstanding and difficult problems between these two
utilities so the benefits of restructuring can be available to NHEC's
customers in a similar time frame and manner as they are to PSNH's customers.
No further considerations are warranted on this issue.

2.   Systems Benefits Charge

     Under the Settlement Agreement, customers would pay a systems benefit
charge, at a level determined by the Commission, to fund certain programs
including but not limited to the Low-Income Electric Assistance Program and
energy efficiency programs.  PSNH would provide a Low-Income Energy
Assistance Program that is consistent with the one proposed by the
Commission's Low-Income Working Group, consistent with the decision of the
Commission in the Final Plan.  Under the EAP as approved, the mil-rate to
fund the program would be 1.5 mils per kWh, collected on all kWh.

     With respect to energy efficiency, the Commission would decide the
appropriate level of funding for any energy efficiency programs to be paid
for through per-kWh rates that are equal for each class, at least at the
outset.  The Settling Parties contemplate that actual efficiency program
designs and budgets, and associated system benefits charges, will be decided
in conjunction with the Commission's review of the report of the Energy
Efficiency Working Group. Pending that review, prior to Competition Day, PSNH
would spend the amounts heretofore ordered by the Commission for energy
efficiency programs.  For the period of time after Competition Day, so long
as the Commission has not rendered a decision about energy efficiency
programs, charges for energy efficiency programs would be 1 mil per kWh
during the first year, 1.5 mils during the second and 2.5 mils during the
third.

     The total Systems Benefits Charge would be no more than 2.5 mils in the
first year after Competition Day, 3 mils in year two, and 4 mils for years
three and following, subject to later adjustments in either direction based
on decisions of the Commission after consideration of the results of the
Working Groups.  While the Settlement Agreement calls for the energy
efficiency charge to be collected in equal cents per kWh for all classes, the
Director of the Governor's Office of Energy and Community Services testified
that Settling Parties contemplate that the specific design and amount of such
charges can be altered in the future by the Commission, as circumstances
suggest.

     The State Team asserted that the proper forum for decisions about
efficiency and spending is the Energy Efficiency Working Group proceeding.
The State Team describes the Settlement's provisions on energy efficiency as
a "placeholder", until the Commission rules on the EEWG's recommendations.
The energy efficiency provisions of the Settlement drew support
from a number of parties, and no party to this proceeding opposed the low-
income assistance program, or "EAP."

     We approve the Settlement Agreement's provisions.  As the Commission
stated in our Final Plan,

We are convinced that, in addition to the direct benefits provided to low
income customers, there are many societal benefits which accrue from the
establishment of a low income assistance program.... [A] low income
assistance program would have the effect of reducing the utilities'
uncollectible accounts, which is a cost of service item recovered from all
customers.  Additionally, ... it is possible there will be a beneficial
impact on property taxes as low income bills are made affordable and fewer
municipal funds are needed for crisis assistance.

     We continue to believe that these are all valid benefits that accrue to
society as the result of a low income program.  The Company has participated
actively on the Low Income Working Group, and substantial efforts are already
underway to prepare for implementation of EAP.  We note that the funding
required for such a program will vary with need, and will be limited by the
cap established by RSA 374-F:4, VIII(b).  In addition, as we have done in the
case of Granite State Electric, to the extent that the low income is not
utilized as anticipated, the SBC will be adjusted downward.

     Energy efficiency can be a valuable tool in meeting the Restructuring
Act's goal of obtaining reduced electricity costs for consumers with minimum
adverse impacts on the environment.  RSA 374-F:1.  The Commission has been
exploring possible ways to reduce subsidies while continuing to assist
customers in overcoming market barriers to maximizing the efficiency of their
electricity usage.  Greater efficiency will not only help mitigate adverse
environmental consequences of electricity use, but will also assist the New
Hampshire economy in maintaining its strength and resilience over the long
term.  With respect to energy efficiency programs, the Commission will have a
full opportunity to address the questions of program administration, overall
energy efficiency funding levels, class-specific programs, and class-specific
charges in the context of our ongoing review of the report of the Energy
Efficiency Working Group.  The proceedings of the Commission in reviewing the
report of the Energy Efficiency Working Group will enable the Commission to
balance these opportunities against the rate impacts of energy efficiency
charges.

3.   Environmental Issues

     The preservation and amelioration of our natural environment has been
raised in a number of contexts in the course of reviewing the Settlement,
including considerations of energy efficiency, treatment of the proposed
environmental remediation fund, questions of sale or retention of nuclear
generating facilities, and allocation of responsibility for decommissioning
such nuclear plants.  In this section, we will consider the proposal of CLF
and SAPL (opposed by the Settling Parties and the OCA) to require PSNH to
cause its presently operating Newington, Schiller and Merrimack generation
facilities to comply with emissions standards for newly built coal and oil-
fired power plants.

     RSA 374-F:3, VIII provides that "[o]ver time, there should be more
equitable treatment of old and new generation sources with regard to air
pollution controls and costs."  The Company's witnesses McDonald and Large
testified to the significant reductions in SO2 and NOx achieved by PSNH at
its Merrimack and Schiller plants in the period since the passage of the
restructuring statute.  PSNH has installed Selective Non-Catalytic Reduction
(SNCR) technology at Schiller Station, and a Combustion Tempering NOx control
system at its Newington Station (along with facilities to permit Newington
station to use cleaner gas for combustion when cost-effective).  In 1999,
PSNH also installed the first utility application of Selective Catalytic
Reduction (SCR) to a coal-fired plant at Merrimack Unit 2, and installed SCR
at Merrimack Unit 1.

     All these efforts have significantly reduced the levels of emissions at
PSNH's plants.  In 1999, PSNH had already achieved more than a 75 percent
reduction in NOx emissions below baseline levels.  The Commission has
supported PSNH in these efforts, most recently by permitting the Company to
retain some of the funds from the sale of future NOx credits for use in
funding emissions control technology, rather than passing them back
immediately through the FPPAC. However, we are aware that new plants have
tougher standards to meet than PSNH's units.

     As we said in our initial Restructuring Plan in 1997, environmental
improvement is an "indispensable public good for which the state and the
nation must make adequate provision."  At that time, the Commission concluded
it would be inappropriate "to independently establish environmental
improvement policies related to electric generators selling power in New
Hampshire."  Statewide Electric Utility Restructuring Plan, 82 NH PUC 122,
190 (1997).  In that Order, the Commission stated:

We do not have the expertise or resources to establish and enforce
environmental policies, and we do not have broad environmental regulatory
authority to optimize environmental regulation.

Id. at 191-92.  The proponents of what CLF describes as "environmental
comparability" have not, on the record before us, provided evidence that
would overcome the inherent paucity of technical expertise, in a commission
established to oversee economic markets, necessary to evaluate their
proposal.  They presented little evidence as to costs and benefits to
consumers of the investments they ask us to require, and what was proffered
relied on secondary or non-expert sources, and was not susceptible to
rigorous analysis.  Further, it appears that the comparability provisions
agreed to by utilities in Massachusetts lack meaningful enforceability, in
light of the preconditions for implementation, such as action by utilities in
upwind states which is considered unlikely.  Given the doubts concerning the
Commission's authority to impose an "old-source review" requirement, and the
fact that such a condition was strongly resisted by the Settling Parties, we
decline on this record to adopt the proposed condition.

     We stress, however, that the Commission has the authority to take other
actions that have as their objective the achievement of long-range
environmental sustainability.  The Commission agrees with CLF that it must
keep this long-range objective in mind and not sacrifice it to shortterm rate
relief.  The Settlement Agreement itself proposes a significant increase in
the funding for energy efficiency in the PSNH service area.  The Commission
will shortly be opening a rulemaking docket to address net metering of small-
scale distributed generation such as photovoltaics.  We have elsewhere in
this Order considered and rejected PSNH's proposals (not a part of the
Settlement Agreement) to eliminate or discourage use by customers of load
control and load management tariffs.

     Further, nothing in the Settlement Agreement precludes us from
considering further actions in an appropriate proceeding.  Such regulatory
actions might include, but are not limited, to delinking the earnings of
transmission and distribution utilities from their sales through a
"revenueper-customer" cap, designing rates in a manner that encourages energy
efficiency, facilitating the use of distributed generation technology that
creates less emissions than traditional centralized generation, and fostering
additional conservation financing options for consumers.

4.   Millstone 3

     The Settlement Agreement provides that on or before Competition Day,
PSNH will transfer its ownership share of Millstone 3 to an affiliate at zero
cost.  PSNH's net book investment in the unit (immediately prior to its
transfer) will be eligible for recovery as a Part 1 stranded cost. The
decommissioning costs associated with this share of the unit are recovered as
a Part 2 stranded cost.  If the transfer by PSNH to an NU affiliate is
delayed, the Settlement Agreement provides that the output is to be sold on
the market and all net proceeds are applied to reduce stranded costs.

     Towards the close of the hearings, PSNH witness Long testified that it
may not be possible to transfer the ownership to another NU affiliate company
so quickly because of the need to receive NRC approvals.  PSNH has therefore
proposed that it would functionally separate the ownership from PSNH, NU
would be responsible for all costs and revenues, and the Company would
account for it as though it had been transferred without having to go through
the actual transfer.

     The State Team did not indicate that it was opposed to this amendment to
the Settlement Agreement, and no other party voiced any opposition.  The
Commission finds that the proposed treatment of functionally separating the
ownership share by accounting for the transfer as if it had occurred is a
reasonable change to the Settlement Agreement and consistent with its
provisions regarding Millstone 3, and will approve it.

5.   Depreciation

     With respect to the issue of depreciation expense and the proper accrual
rates for PSNH's fixed assets, we approve the revised accrual rates as
recommended by Non-Settling Staff witness James Cunningham pursuant to our
authority under RSA 374:10.  Mr. Cunningham's recommendation results from
PSNH's 1997 depreciation study, a study which is preferable to the outdated
1986 study.  The revised accrual rates reduce PSNH's total depreciation
expense by $7.3 million on a total company basis prior to divestiture of
generation assets.  The Commission directs the Company to implement the
revised depreciation accrual rates effective with the date of this order.
This change will provide greater accuracy in PSNH's depreciation expense and
the resulting impact on the Company's reported earnings, as well as the
impact on stranded costs.  By implementing the revised rates for the
fossil/hydro assets now, which are higher than those currently being used,
stranded costs will be reduced by up to $1.5 million annually through a
reduction of the net book value of these assets without any corresponding
change in customer rates.

     The Commission specifically approves the 10-year life extension of
Transmission and Distribution assets as proposed in the Settlement Agreement.
By booking these new rates immediately, depreciation expense is reduced by
about $9.2 million and will not be overstated during the IDCP when the basis
for the delivery rate case at the end of the period is established. This will
also provide for a more accurate measurement of PSNH's earnings during the
IDCP.  We further require PSNH to prepare and file as a part of its delivery
rate case at the end of the IDCP a revised depreciation study so that rates
can be reviewed at that time.

     With respect to the issue of dismantlement costs continuing to be
included in Merrimack Station Unit 1, Exhibit 77 from Phase I of the hearings
shows that PSNH had recovered 100 percent of its estimated dismantlement
expenses by 1995.  Since that time, the Company has continued to accumulate
reserves in excess of its estimated dismantlement requirements.  We agree
with Staff witness Cunningham that PSNH should not continue to accrue these
costs which are approximately $1 million annually.  In the event that
Merrimack Station and other steam production facilities should still be owned
by PSNH when dismantlement of the plant begins, PSNH can come before this
Commission and request recovery of costs which it may not have previously
recovered through its prior depreciation accruals.  Until such time, we will
not allow the company to continue to recover dismantlement costs in its
depreciation rates.

     Another related issue discussed by Mr. Cunningham is that of extending
the life of Merrimack Unit 1.  He has recommended that, based on the capital
additions made by PSNH during the 1996-1999 time period, it makes sense to
extend the life for depreciation purposes from 2002 to 2005.  Although the
Company's position is that its 1997 depreciation study utilizes a 2002
deactivation date, PSNH has given no indication that Merrimack Unit 1 will be
deactivated in 2002.  We therefore believe that, based on Mr. Cunningham's
recommendation, it is appropriate to provide for an extended life for
Merrimack Unit 1 and to calculate depreciation for the unit accordingly.

     The Company has also proposed to provide amortization of easements.  Mr.
Cunningham has recommended that such a proposal be rejected since easements,
like land, have no determinate life.  PSNH did not substantively rebut this
position, except to state its disagreement.  Ph. II, Tr. Day XIX, at 219.
Therefore, we will accept Mr. Cunningham's recommendation and not allow for
amortization on easements.

     Mr. Cunningham has also recommended that certain General Plant accounts
of PSNH be depreciated using industry average lives.  He indicates that the
depreciation study did not provide documentation to support the proposed
lives for accounts 391, 393, 394, 395, 397, and 398. Again, PSNH did not
substantively rebut Mr. Cunningham's recommendation, except to state its
disagreement.  Ph. II, Tr. Day XIX, at 220.  Therefore, until PSNH files its
new depreciation study at the conclusion of the IDCP, the company should use
industry average lives for these accounts.

     With respect to the Company's proposal to amortize rather than
depreciate certain General Plant accounts, Mr. Cunningham has recommended
further study.  He indicated that some of the General Plant accounts that
PSNH indicated were "low dollar value" actually contain a number of
individual plant items that have high dollar value.  Ph. II, Tr. Day V, at
143-144.  Therefore, until PSNH files its new depreciation study at the
conclusion of the IDCP, the Company should continue to use depreciation
rather than amortization.

     Finally, Mr. Cunningham has addressed the issue of the reduction of net
salvage values for certain accounts.  These include Structures and
Improvements from 20 percent to zero; and Office Furniture, Shop Tools, and
Power Operated Equipment from 10 percent to zero.  He indicates that the
depreciation study provided no documentation for such reductions.  Except to
state its disagreement with it, PSNH has provided no substantive rebuttal to
this position.  Ph. II, Tr. Day XIX, at 221.  Therefore, we will accept Mr.
Cunningham's recommendation and not allow reductions in salvage values.  This
issue may be revisited when PSNH files its updated depreciation study at the
conclusion of the IDCP.

6.   Small Power Producers

     The single largest component of PSNH's stranded costs is the cost
associated with purchases from facilities providing power to PSNH under the
Public Utilities Regulatory Policies Act (PURPA) and the Limited Electrical
Energy Producers Act of 1978 (LEEPA), RSA Chapter 362-A.  Mr. McCluskey
estimates the stranded costs of small power producers at $710 million,
present value.  The Settling Staff state that the Settlement Agreement uses a
present value of $800 million as the level of stranded costs due to SPP
purchase commitments by PSNH.   Estimates of the above market costs due to
small power producers are based on the estimated, discounted annual revenues
that would be paid to the small power producers over the terms of their rate
orders minus their annual, discounted expected market values.

     Stranded costs due to mandated purchases from the small power producers
are recoverable under Part 2 Stranded Costs in the Settlement Agreement.
Many parties to this proceeding have expressed concern over the magnitude of
the above market costs from SPPs. Rep. Bradley states that reducing the costs
of SPPs is critical to the "long-term economic vitality of New Hampshire's
economy" (Br. at 14).  He recognizes that buy-downs may not be possible prior
to implementation of the Settlement Agreement.  He would support further
monetary improvements to the Settlement Agreement if no buy-downs are
consummated prior to Competition Day in order to keep the savings level at 18
percent as he believes the Transition Service prices will erode the 18
percent rate decrease.  As a potential offset to further "monetary
improvements" by PSNH to the Settlement Agreement,  Rep. Bradley would allow
PSNH to share in the savings that would result from buy-downs of SPP rate
orders. Rep. Bradley would allow PSNH to use $75 million of securitization
for SPP buydowns.  The $75 million would come from the elimination of $75
million of securitization related to the Acquisition Premium allowed by the
Settlement Agreement.   BIA also recognizes the significant cost of the SPPs
and proposes backto-back auctions of SPP power, similar to what has been used
in Maine, as a way to minimize the costs of the SPP rate orders.

     Whether the actual stranded costs of small power producers is $710
million or $800 million, we agree with Rep. Bradley that the absolute level
of stranded costs associated with the small power producers could have
serious and adverse effects on the New Hampshire economy until the SPP's rate
orders terminate.  We remain disappointed that PSNH did not consummate the
BioEnergy Corporation agreement we approved conditionally in Order No. 22,479
(January 15, 1997) and clarified on February 17, 1998 based on BioEnergy's
Motion for Rehearing (see Order No. 22,848); however, we believe the benefits
of the Settlement Agreement warrant moving forward as soon as possible.   The
Settlement Agreement, consistent with RSA 374-F:3 XII(b), allows for the
recovery of the over-market power purchases made in accordance with state or
federal mandates and we will approve them as such. SA, at ll:541-561.    If
PSNH can reach an agreement with one or more of the SPPs, and we encourage
PSNH and the small power producers to try and reach an agreement as soon as
possible, we will allow PSNH to use an appropriate level of securitization,
if necessary, to effectuate the buy-downs or buyouts of  SPP rate orders.
The potential savings of renegotiated SPP agreements decrease with the
passage of time.  To emphasize the importance of time's effect on the value
of SPP mitigation,  we find a shared savings approach to SPP mitigation to be
in the public interest.  We will allow PSNH to retain 20 percent of the
savings due to agreements reached between PSNH and SPPs before the end of one
year from the date of this Order that are subsequently approved by the
Commission; thereafter, PSNH's share will fall to 10 percent for one
additional year.   We find that the marketing provision of power from SPPs
contained in Section IX (B) (2) and (3) of the Settlement Agreement is sound
and that no changes are necessary or required.


7.   Settlement Agreement Language Regarding Binding Effect Of Commission
Approval

     The Commission has previously addressed its concerns with certain
language appearing on page 73 of the Settlement Agreement which provides that
the Commission's approval "shall endure so long as necessary to fulfill the
express objectives of this Agreement" and that such approval "is binding with
respect to matters contained herein."  In Order No. 23,346, issued November
16, 1999, the Commission stated that:

     The general purpose of this language would appear to restrict the
ability of later Commissions to alter in any way the decisions embodied in
the Settlement Agreement once it is approved.  With regard to the creation of
an irrevocable property right in the receivables that would be used to retire
Rate Reduction Bonds, should securitization be approved, such a limitation on
future Commissions would be appropriate within the language of the statute
creating such a property interest.  However, beyond that unique instance
where it is contemplated that the Legislature would specifically limit the
Commission's authority, we reiterate a conclusion we have previously stated
in a similar context: "We do not believe we have the authority to bind the
State of New Hampshire, other state agencies or future Public Utilities
Commissions." Public Service Company of New Hampshire, 82 NH PUC 21, 24
(1997).

     By statute, we are vested with the express authority, upon notice and
hearing, to "alter, amend, suspend, annul, set aside or otherwise modify any
order" we issue.  RSA 365:28; see also RSA 365:25 (providing that rates
authorized by Commission "shall remain in effect until altered by a
subsequent order of the commission").  In our view, only the Legislature can
divest the Commission of powers that the Legislature has specifically vested
in us and our successors.

     The Commission then determined that it would not approve the above-
quoted language as part of the proposed Settlement Agreement, and offered the
Settling Parties three options: (1) to remove the offending language from the
Settlement Agreement altogether; (2) to accept the imposition by the
Commission of a condition that will render the language in question
inoperative; or (3) to seek a Legislative remedy of this matter.

     Prior to the start of the Phase II hearings, neither the State Team nor
PSNH indicated whether they would accept any of the offered alternatives, nor
did they state that the Commission's determination to render this particular
language ineffective would cause the signatories to withdraw from the
Agreement or modify their concurrence.

     During the first day of Phase II hearings, several of the Non-Settling
Parties requested that the Commission require the Settling Parties to
indicate their position on this issue.  After much discussion of this issue,
PSNH responded that, "[i]n the event that the Commission changes the
agreement with respect to this one particular issue, that will not cause the
Company to reject the Settlement."  Ph. II, Tr. Day I, at 139:21.

     Accordingly, the Commission reaffirms its previous decision on this
matter and finds that the conditional approvals granted in this Order are
subject to the further condition that the Settlement Agreement language
referenced above shall be interpreted in a manner that is consistent with the
statutory authority of the Commission and shall not create any greater
binding or precedential effect than that which is normally accorded a final
order of the Commission.

8.   Resumption Of Dividends

     Section XIV (B) of the Settlement Agreement provides that PSNH will not
make dividend payments to its parent, NU, until the earliest of the date the
write-offs associated with the Agreement are taken, or the date the Agreement
is terminated or disapproved by the Commission. PSNH remains subject to a
restriction against its payment of dividends to its parent NU.  This
restriction was extended by the Commission in PSNH's most recent financing
case, Docket DE 00-016, in Order No. 23,416, issued March 1, 2000.

     The Commission approves the portion of this section of the Settlement
Agreement providing for payment of dividends once the write-offs are taken.
However, if the Settlement Agreement is terminated, PSNH will remain under
the dividend prohibition until such time as the Commission orders otherwise.

9.   Notification By Settling Parties In Response To Commission Modification

     Section XVII (D) of the Settlement Agreement provides that if the
Commission does not approve the Agreement in its entirety, without
modification, the Settling Parties shall have an opportunity to amend or
terminate the Agreement.  The Commission has determined that the Settling
Parties shall notify the Commission within ten days of the date of this Order
whether they will accept the Commission's conditions for approval and modify
the Settlement Agreement accordingly.

10.   Summary of Estimated Rate Effects of Order

     The changes we will require to stranded cost recovery and Transition
Service rates will result in changes to the overall percentage rate decrease
resulting from the Settlement Agreement. With our determinations on rate
design issues, this Order will also affect the allocation of costs to
classes, and the percentage decrease each class may expect.  The Commission
will require the Company to redo its financial model to reflect the changes
as described in this Order, and to make a proposal for its recovery of net
Hydro-Quebec costs, including allocation of such costs to classes.  Until the
Commission reviews the results of the Company's modeling, it is not possible
to state with precision the resulting overall average rate, the average rate
per class, nor the associated percentage decreases by class.  However, based
on our preliminary estimates, we expect that the average overall rate
reduction will be approximately 18 percent.  The table below provides an
estimate of the class-by-class and component-by-component effects of this
Order.

Summary:  Estimated Average Rates by Class and Estimated Average Percent
Reduction in Rates by Class

Rate Class

Residential
DSC  3.731
SCRC  3.555
SBC  0.25
Tax  0.055
HQ  0.1
Total DSC  7.69
TS  4.00
Total Rate  11.69
% Decrease  19.56%

Small General
DSC  2.819
SCRC  3.400
SBC  0.25
Tax  0.055
HQ  0.1
Total DSC  6.62
TS  4.00
Total Rate  10.62
% Decrease  17.36%

Primary General
DSC  1.424
SCRC  3.270
SBC  0.25
Tax  0.055
HQ  0.1
Total DSC  5.10
TS  4.00
Total Rate  9.10
% Decrease  17.16%

Large General
DSC  1.166
SCRC  3.046
SBC  0.25
Tax  0.055
HQ  0.1
Total DSC  4.62
TS  4.00
Total Rate  8.62
% Decrease  15.79%

Outdoor Lighting
DSC  13.306
SCRC  3.400
SBC  0.25
Tax  0.055
HQ  0.1
Total DSC  17.11
TS  4.00
Total Rate  21.11
% Decrease  18.27%

Overall Average
DSC  2.80
SCRC  3.400
SBC  0.25
Tax  0.055
HQ  0.1
Total DSC  6.605
TS  4.00
Total Rate  10.61
% Decrease  18.23%


Q.CONDITIONS TO SETTLEMENT AGREEMENT

     In summary, the Commission has determined that it will accept the
Settlement Agreement as being in the public interest and consistent with New
Hampshire law, and as a final resolution of the dockets listed therein,
subject to the following conditions:

1.   Amendments to Stranded Cost Recovery

               a) PSNH shall credit the Accumulated Deferred Income Taxes
associated with Part 3 non-securitized stranded costs at the stipulated rate
of return, rather than at the return on the Rate Reduction Bonds as provided
for in the Settlement Agreement.  This will reduce stranded cost recovery by
approximately $22.4 million.

               b)  PSNH shall not be allowed to recover the HQ support
payments as a stranded cost, and must credit its Part 3 Stranded Costs
accordingly; it will be allowed to recover the ongoing support payments with
an offset for any revenues received in a manner subject to further Commission
review.  In addition, the Recovery End Date shall be adjusted to account for
this reduction in Part 3 Stranded Costs.

               c)   Section VIII (K) of the Settlement Agreement, relating to
the Commission's determination of a confidential minimum bid for Seabrook,
shall be modified to eliminate the phrase, "based on comparable transactions
and" from page 50, line 1420 of the Agreement.

               d)  Part 3 Stranded Costs shall be reduced by $78.6 million to
reflect a credit of the $65.6 million generation-related regulatory liability
and $13 million deferred receivable.

               e)  PSNH is directed to recalculate the Recovery End Date in
accordance with the terms of the Settlement Agreement and the recalculated
SCRC, with the limitation of a two-month "cushion."  In addition, because of
the elimination of $62 million associated with HQ from Part 3 stranded costs,
PSNH is also required to propose, within ten calendar days of this
Order, an additional adjustment to the Recovery End Date to reflect the
smaller total of Part 3 stranded costs.

               f)  The Commission will direct PSNH to make a compliance
filing of a forecasted rate path and supporting schedules incorporating the
changes to stranded costs as indicated, including the changes as outlined in
Exhibit 86 from Phase I, within ten calendar days of this Order.  In
addition, this filing shall incorporate corrections for the items agreed to
by PSNH during the hearings, including treatment of the NOx credits, the loss
on reacquired debt, and the credits to the FPPAC.

2.   Transition Service

               a)  In order to reduce expected deferrals of stranded cost
recovery, and to send customers more realistic price signals, the price for
Transition Service will be changed to 4.0, 4.1, and  4.2 cents per kWh over
the three years of the Transition Service period, an increase over the 3.7,
3.8, and 3.9 cents per kWh in the Settlement Agreement.

               b)  We will allow PSNH to use existing resources on an interim
basis to provide Transition Service.

               c)  The Commission finds that the process outlined by the
Settling Parties for awarding Transition Service is appropriate.  Affiliates
of PSNH will not be prevented from bidding.  Because a PSNH affiliate intends
to bid on Transition Service, PSNH must hire an independent consultant to
conduct the process for acquiring Transition Service, and Commission Staff
will have plenary oversight authority.

3.   Securitization

               a)  The Commission will, subject to legislative approval,
allow $688 million to be securitized, including $17 million for issuance
expenses.  The $37 million decrease in securitized stranded costs will be
shifted back to Part 3 stranded costs.  We recognize this changes the PSNH
model shown in Exhibit 86; therefore, we expect PSNH to reflect those changes
in its filing indicating whether it accepts the conditions in this Order.

               b)  If the Company is able to negotiate reductions in its
existing SPP rate order obligations, as set forth in Sections VIII (G)(3) and
(P)(6) of this Order, the Commission will consider allowing an additional
amount of securitization up to $37 million.

               c)  We determine that the term "Stipulated Rate of Return"
incorporates a return on equity of 8 percent after tax, an equity ratio of 40
percent, and the weighted cost of PSNH's non-securitized long-term debt, as
provided in the Settlement Agreement at 10:268.

               d)  PSNH's commitment in the Settlement Agreement at lines
1691-1692 to "cooperate to establish market power measurements and benchmarks
that may be used to monitor how the ISO-NE power marketplace is operating,"
must be modified.  First, NU must join in this commitment because PSNH
participates in NEPOOL through NU.  Second, the phrase "that may be used"
must be replaced with the phrase "that will be effective."  Finally, we will
require PSNH to file reports quarterly with the Commission, through the IDCP,
of the positions of NU or any NU affiliate regarding market power monitoring
and mitigation efforts in NEPOOL, before the ISO or before FERC.

4.   Stranded Cost Recovery Charge

          The Commission has determined that, for the initial delivery charge
period, the SCRC shall be based on a melding of OCA' s recommended approach
and the Company's mechanism, by adjusting the SCRC for each class to a point
halfway between the SCRC produced by the Company's mechanism and an equal
cents-per-kWh basis as proposed by OCA.

5.   Proposed ConEd/NU "Merger"

          The Commission finds that there has been no agreement between
Settling Parties on the issues of the standard of review of the merger and
whether merger savings may be required to be passed through to ratepayers
during the 30-month IDCP.  As a result, the Commission concludes that there
is nothing in the Settlement Agreement that would prohibit it from taking
action on these questions in the context of the merger docket.  The
Commission will defer to Docket DE 00-009 the particular questions concerning
the standard of approval by which the transaction is to be reviewed and the
nature and extent of any conditions that should be placed on our approval of
the merger.  We will take administrative notice in Docket DE 00-009 of the
record in this docket to preserve the record on these issues.

6.   Asset Divestiture

               a)  PSNH affiliates are precluded from bidding on PSNH's
generation assets.  This ban would also apply to Consolidated Edison
companies if its proposed merger with Northeast Utilities is completed prior
to the initiation of the divestiture process.  The Commission has determined
that it is not necessary to ban Consolidated Edison companies from bidding on
PSNH assets during the pendency of the merger proceedings.

               b)  The Commission directs PSNH to inquire of Consolidated
Edison whether any of its companies intend to bid on PSNH's assets.  PSNH
shall furnish the Commission with a written response from Consolidated Edison
no later than two weeks from the date of this Order.  If Consolidated Edison
indicates an intent to bid or an unwillingness to make its intentions known
by the date indicated above, PSNH must hire an independent contractor,
acceptable to the Commission Staff, to conduct the asset sale.

               c)  PSNH and NU are required to take whatever additional steps
are necessary (including, but not limited to adopting a code of conduct in
consultation with PUC Staff) to make the asset divestiture process "fair,
equitable and impartial to all bidders" as is required by line 1155 of the
Settlement Agreement.

               d)  PSNH is required to treat Consolidated Edison and the so-
called "NU bid team" as it would any other prospective buyer of the Company's
generating assets in accordance with the proposed code of conduct governing
the asset divestiture process.

               e)  The divestiture of PSNH's fossil assets shall be separated
from the sale of its hydro assets.  The divestiture of the fossil assets
shall occur first and the sale of the hydro assets shall occur between six
months and one year following "Competition Day" to accommodate the special
timing needs of municipalities as set forth in Section VIII (M) of this
Order.  The Commission will not accept the GOECS and BIA proposal for linked
bids.

               f)  PSNH shall inform all bidders of the "Key Terms of Sale"
as detailed in the MacDonald/Large pre-filed testimony in Phase I.

7.   Municipal Participation in Auction and Proceeds from Sale of Garvins
Falls Land

               a)  The restriction in the Settlement Agreement to limit
municipal participation in the second round of asset bids must be removed
from the hydro auction process.

               b)  Municipalities shall be able to purchase facilities
outside of their municipal borders.  The municipalities should not be given
any special treatment for such purchases other than to address time and
flexibility concerns as noted above.

               c)  The Commission finds that it is reasonable for the City of
Concord to have input in the development of the auction criteria for this
parcel.  However, such participation shall be limited to the City's review
and comment on the proposed auction criteria.

               d)  The Commission requires a change to the Settlement
Agreement regarding the three parcels of land identified at 46:1317-1321 of
the Agreement: any parcels of land at the three sites that are below the line
shall be subject to the 50/50 sharing of the amount by which the net proceeds
exceed the net book value; any parcels that are above the line, 100 percent
of the net proceeds from the sale of those parcels shall be used as a credit
against stranded costs.

               e)  The Commission has determined that Exhibits 195, 196, and
197 are irrelevant to this proceeding, will not be made a part of the record,
and will be returned to the City of Manchester.


8.   Nuclear Decommissioning

          The Commission accepts PSNH's clarification that customers will be
entitled to a refund of any overpayments from PSNH's customers which result
from "decommissioning costs paid via present 'bundled' rates or via future
'unbundled' SCRC charges."  Ratepayer contributions to the fund and any
earnings related to those contributions must be accounted for in a manner
whereby they may be segregated, and the refund of the contributions in excess
of need must be assured.  PSNH is required, at a reasonable amount of time
prior to the sale of Seabrook, to provide the Commission an explanation of
how it will assure that such an appropriate mechanism will be in place.  The
surcharge to ratepayers must be able to be adjusted downward in the event
that the estimate of decommissioning costs on which the surcharge is
currently based decreases after the sale of the facility, but before the
facility is shut down.
17.Rate Design

               a)  The Commission will require PSNH's tariffs to cite that
the provisions of the Settlement Agreement control in the case of a
difference between the two.

               b)  The Commission does not approve the closure of the time-
of-use and load-controlled rates at this time, nor the intentional limitation
of reductions as a tool to promote migration off such rates.  The Company
will be permitted to renew its proposals during the T&D rate case anticipated
to be filed shortly before the IDCP ends.

               c)  The Commission denies PSNH's proposal to terminate the
Elderly Customer Discount one year after Competition Day.

               d)  The Company is required to develop an updated N-5
Interruptible Service tariff, and file it with the Commission, in time to be
useful in helping address this summer's peak, with a proposal for any
improvements to N-5 that will enhance its usefulness as a reliability tool.

               e)  The Commission will not require PSNH to unbundle its T&D
at this time, but will reserve the authority to reconsider this issue at such
time as we deem appropriate.

               f)  The Commission does not approve PSNH's proposed late fees,
field collection fees, and service establishment and meter connection fees in
this docket, but PSNH may renew its request for such new and increased
charges in its next overall residential rate design filing.  PSNH's proposed
tariffs concerning terms and conditions for energy service providers and line
extensions are approved.

               g)  With regard to Special Contracts, we will require the
Company to present amendments to the contracts to those customers for their
acceptance, and for filing with the Commission.  We also will require the
Company to keep the Commission informed periodically as to the elections that
such Special Contract customers have made with respect to the additional
options provided as a result of the Settlement Agreement.  Further, we direct
the Company, if it accepts the conditions for approval of the Settlement
Agreement, to make a proposal for treatment of the revenue and rate impacts
of the increase to Transition Service rates with respect to Special
Contracts, as part of its compliance filing.  We will direct the Company, if
it accepts the conditions for approval of the Settlement Agreement, to make a
proposal for treatment of the revenue and rate impacts of the increase to
Transition Service rates with respect to Special Contracts, as part of its
compliance filing.

10.   Other Issues

               a)  The Commission approves the revised accrual rates and
other recommendations of Non-Settling Staff witness James Cunningham and
requires their application by the Company.

               b)  The Commission finds that PSNH's proposal to functionally
separate its ownership share of the Millstone 3 plant by accounting for the
proposed transfer as if it had occurred is a reasonable change to the
Settlement Agreement and consistent with its provisions, and will approve it.

               c)  The Commission will allow PSNH to retain 20 percent of the
savings due to agreements reached between PSNH and SPPs that are reached
within one year of this Order and are subsequently approved by the
Commission; PSNH's share will fall to 10 percent if such agreement is reached
within two years and subsequently approved.

               d)  The language in the Settlement Agreement at 73:2089-2097
shall be interpreted in a manner that is consistent with the statutory
authority of the Commission and shall not create any greater binding or
precedential effect than that which is normally accorded a final order of the
Commission.

               e)  If the Settlement Agreement is terminated, PSNH will
remain under the dividend prohibition until such time as the Commission
orders otherwise.


     Based upon the foregoing, it is hereby

     ORDERED, that the Settlement Agreement is hereby approved, subject to
its amendment consistent with the conditions set forth above.

     By order of the Public Utilities Commission of New Hampshire this 19th
day of April, 2000.




/s/ Douglas L. Patch           /s/ Susan S. Geiger      /s/ Nancy Brockway
   Douglas L. Patch                Susan S. Geiger          Nancy Brockway
   Chairman                        Commissioner              Commissioner


Attested by:

/s/ Debra A. Howland
Debra A. Howland
Acting Executive Director and Secretary


Glossary of Acronyms Used in this Order:

Acronym:
ADIT
Term:
Accumulated Deferred Income Taxes

Acronym:
CAP
Term:
Community Action Programs

Acronym:
CL&P
Term:
Connecticut Light & Power

Acronym:
CLF
Term:
Conservation Law Foundation

Acronym:
CRR
Term:
Campaign for Ratepayers' Rights

Acronym:
CWIP
Term:
Construction Work in Progress

Acronym:
DCF
Term:
Discounted Cash Flow

Acronym:
DSC
Term:
Delivery Service Charge

Acronym:
EITF
Term:
Emerging Issues Task Force

Acronym:
EWG
Term:
Exempt Wholesale Generator

Acronym:
FERC
Term:
Federal Energy Regulatory Commission

Acronym:
FPA
Term:
Federal Power Act

Acronym:
FPPAC
Term:
Fuel and Purchased Power Adjustment Clause

Acronym:
FTC
Term:
Federal Trade Commission

Acronym:
GOECS
Term:
Governor's Office of Energy and Community Services

Acronym:
GSEC
Term:
Granite State Electric Company

Acronym:
IBEW
Term:
International Brotherhood of Electrical Workers

Acronym:
IDCP
Term:
Interim Delivery Charge Period

Acronym:
IPPS
Term:
Independent Power Producers

Acronym:
MOU
Term:
Memorandum of Understanding

Acronym:
NAEC
Term:
North Atlantic Energy Corporation

Acronym:
NEP
Term:
New England Power

Acronym:
NEPOOL
Term:
New England Power Pool

Acronym:
NHCUC
Term:
New Hampshire Consumers' Utility Cooperative

Acronym:
NHEC
Term:
New Hampshire Electric Cooperative

Acronym:
NOx
Term:
Nitrogen Oxide

Acronym:
NU
Term:
Northeast Utilities

Acronym:
NUSCO
Term:
Northeast Utilities Services Company

Acronym:
PSNH
Term:
Public Service Company of New Hampshire

Acronym:
PUHCA
Term:
Public Utilities Holding Company Act

Acronym:
PURPA
Term:
Public Utilities Regulatory Policies Act of 1978

Acronym:
RRBs
Term:
Rate Reduction Bonds

Acronym:
RED
Term:
Recovery End Date

Acronym:
ROE
Term:
Return on Equity

Acronym:
SAPL
Term:
Seacoast Anti-Pollution League

Acronym:
SBC
Term:
System Benefits Charge

Acronym:
SCRC
Term:
Stranded Cost Recovery Charge

Acronym:
SEC
Term:
Securities and Exchange Commission

Acronym:
SOHO
Term:
Save Our Homes Organization

Acronym:
SPPs
Term:
Small Power Producers

Acronym:
SPSE
Term:
Special Purpose Securitization Entity

Acronym:
WMECO
Term:
Western Massachusetts Electric Company



New Hampshire Public Utilities Commission
8 Old Suncook Road
Concord, New Hampshire 03301-7319





Footnotes

1.  PSNH cited the reasons for its bankruptcy as: the magnitude of its
investment in Seabrook; the delay in obtaining licensing approval for
Seabrook from the federal Nuclear Regulatory Commission; and its inability to
realize any return on its investment until Seabrook went on-line, due to the
New Hampshire Legislature's enactment of RSA 378:30-a (the "anti-CWIP" law)
which prohibits utilities from charging rates that would enable them to
recover the cost of construction work in progress prior to a plant's
commercial operation.

2.  The other interdependent policy principles detailed in the Act include:
system reliability, customer choice, regulation and unbundling of services
and rates, open access to transmission and distribution facilities, universal
service, benefits for all consumers, full and fair competition, environmental
improvement, renewable energy resources, energy efficiency, regionalism,
administrative processes and timeliness of unbundling rates and services and
implementing full, statewide customer choice. RSA 374-F:3.

3.  See Statewide Electric Utility Restructuring Plan, 82 NH PUC 122 (1997);
see also Statewide Electric Utility Restructuring Plan (Public Service
Company of New Hampshire), 82 NH PUC 101 (1997).

4.  That day, the Commission also issued orders determining interim stranded
cost charges for Connecticut Valley Electric Company, Concord Electric and
Exeter & Hampton Electric Companies, Granite State Electric Company and the
New Hampshire Electric Cooperative. See Orders No. 22,509-22,511 and Order
No. 22,513.

5.  For a somewhat more complete history of the federal lawsuit, the reader
is referred to Public Service Company of New Hampshire v. Patch, 167 F.2d 15
(1st Cir. 1998) (affirming trial court's granting of preliminary injunctive
relief and non-abstention), and Public Service Company of New Hampshire v.
Patch, 167 F.2d 29 (1st Cir. 1998) (vacating trial court's injunction
ordering Commission to increase rates of intervenor Connecticut Valley
Electric Company). Subsequent to those appellate decisions, the U.S. District
Court entered an order on August 24, 1999 providing that the litigation is
stayed as to PSNH and NU until either the Settlement Agreement is implemented
or the Court is notified by the Commission, PSNH or NU that the Settlement
Agreement will not be implemented. In addition, the Court stayed a previous
order that the Commission proceed forthwith to determine PSNH's interim
stranded cost charge.

6.  On October 7, 1998, the Commission approved a settlement agreement in
connection with Granite State Electric Company (GSEC) and its compliance
filing, making GSEC the first New Hampshire utility to offer retail choice to
its customers. See Granite State Electric Co., 83 NH PUC 532 (1998). And on
December 20, 1999, the Commission gave final approval to plans by the New
Hampshire Electric Cooperative (NHEC) to begin retail competition in NHEC's
service territory as of January 1, 2000. See Order No. 23,369 (December 20,
1999).

7.  Mr. Getz was designated by the Commission to participate in negotiations
between PSNH, NU and the Governor's Office on behalf of the Staff of the
Commission. Throughout these negotiations, the Commission treated Mr. Getz,
Mr. Michael Canata (the Chief Engineer of the Commission) and the rest of the
Settlement Staff as if they had been bifurcated in accordance with RSA
363:32. The Commission subsequently formalized this designation in its Order
No. 23,299. Mr. Getz signed the MOU, and subsequently the Settlement
Agreement, on behalf of the Settlement Staff.

8.  Securitization refers to the issuance of so-called Rate Reduction Bonds
(RRBs), described by the Legislature as: instruments underwritten for
recovery by a guaranteed promise of customer repayment as part of the
stranded cost recovery charge on a customer's bill. These bonds' irrevocable
guarantee of repayment creates a secure expectation of performance and thus
allows for an attractive rate of refinancing of a utility's stranded costs.
1999 N.H. Laws 289:2, codified as RSA 369-A:1, V.

9.  Cabletron Systems, Inc., Enron, the Campaign for Ratepayer Rights, the
Office of Consumer Advocate, EnerDev Inc., and Granite State Taxpayers, Inc.

10.  The Commission also conducted a series of public hearings throughout
October 1999 in Rochester, Dover, Berlin, Keene, Nashua, Manchester and
Concord in an effort to ascertain public sentiment about the settlement
proposal.

11.  The Commission noted that, with respect to legislative changes, there
may be constitutional limits to the power of the Legislature to bind itself
in its future exercise of police powers. The Commission deemed that issue to
be outside our jurisdiction.

12.  The Settlement Agreement, p. 10, defines "stipulated rate of return" as:
"A rate of return calculated assuming a return on equity of 8% after tax, an
equity ratio of 40%, and the weighted cost of PSNH's non-securitized long-
term debt. The Stipulated Rate of Return will be computed as of two dates.
The first calculation will occur on Competition Day, and will take into
account the reduction in long-term debt costs occasioned by the issuance of
the RRBs. The second calculation will occur as of the date of closing of the
sale of PSNH's fossil/hydro assets and will take into account any additional
reduction in long-term debt costs occasioned by the proceeds from the sale of
those assets."

13.  PSNH guaranteed interest rates of 6.25% if the RRBs issue on or before
December 31, 1999; 7.25% if the RRBs issue during the time period between
January 1, 2000 through and including June 30, 2000. PSNH states that this
rate guarantee will not apply If the RRBs issue on or after July 1, 2000 or
if such bonds do not carry a Triple-A Rating.

14.  See FERC Order 888, Promoting Wholesale Competition through Open Access
Non-discriminatory Transmission Service by Public Utilities and Recovery of
Stranded Costs by Public Utilities and Transmitting Utilities.

15.  PSNH explicitly reserves the right to sell its interest in the Wyman 4
generation station in Maine outside the auction process. However, in the
event PSNH does not sell its Wyman 4 interest prior to approval of the
Settlement Agreement, this asset would also be included in the auction.

16.  According to PSNH witness Mark A. Englander, the expected targeted
balance of the capital subaccount is at least 0.50 percent of the RRB
issuance amount and the expected targeted balance of the overcollaterization
account is also at least 0.50 percent of the issuance amount.

17.  This list is largely similar, but not identical, to the list of dockets
that were stayed pending the outcome of this proceeding.

18.  Appended to Representative Bradley's post-hearing brief is a letter
indicating that the Legislative Oversight Committee on Electric Utility
Restructuring reviewed the brief and voted 10-0 to express "general support"
for his brief as "being reflective of the direction of the Committee's
thinking."

19.  The testimony of Messrs. Naylor and Kosnaski is described in detail,
infra.

20.  The State Team's brief also contains the statement that Section XIV(C)
of the Settlement Agreement, which discusses sales or mergers, was negotiated
before NU began merger discussions with Consolidated Edison.

21.  We have assumed an effective date for the base rate decrease of July 1,
2000. In part, this date was assumed to make the comparisons between models
simpler. It is the Commission's intent, however, to proceed immediately with
Docket No. 97-059 should the Settlement Agreement not be implemented, and
therefore this date is a reasonable assumption.

22.  Both figures are a present value based upon a 10 percent discount rate.

23.  August 5, 1998 NU press release quoted in Ph. II, Ex. 103, at 14.

24.  We note that the Connecticut Department of Public Utility Control made
this same finding with respect to CL&P's interest in the HQ inter-tie. See
Ph. II, Ex. No. 110, at 31-33.

25.  Mr. Mahoney stated that CL&P had a tariff on file at FERC associated
with HQ. It is our understanding that pursuant to FERC Order No. 888, this
tariff is applicable to all NEPOOL participants with an ownership interest in
the HQ line, and allows for the provision of firm and non-firm point-to-point
transmission service.

26.  The session law provides that the Commission shall, as part of its order
addressing a settlement proposal, "include a determination of whether the
implementation of securitization as part of a utility's restructuring plan
will result in benefits to customers that are substantially consistent with
the principles contained in RSA 374-F:3 and RSA 369-A:1, X and with RSA 369-
A:1, XI."

27.  As discussed in Section VIII (F)(4) above, the Commission has determined
to deny stranded cost recovery for the HQ transmission support payments, but
will allow recovery of this expense on an ongoing basis, and has requested a
recovery proposal from the Settling Parties. Thus, the amount included in
this chart is an estimation only.

28.  In Docket DR 98-139, PSNH sought approval to amend the contracts so as
not to increase the rate for such customers as a result of the increase in
the FPPAC BA occasioned by the amortization of half of the NU Acquisition
Premium. The Company also proposed that it would hold other customers
harmless from the effects of this adjustment, during the period up to
Competition Day. We approved the Company's proposal, and ordered that the
rates approved in that docket would "remain in effect ... until the
Commission orders otherwise in compliance with an approved restructuring
plan...." Order No. 23,139 at 10.

29.  The dispute between NHEC and PSNH revolved around the interpretation of
a number of contractual terms emanating from our approval in 1995 of how to
set long-term avoided costs for NHEC and our approval in 1996 establishing
final guidelines for a retail competition pilot program for NHEC. See Order
No. 22,033 in Docket No. DR 95-250. The contractual disputes were decided by
the FERC initially on May 29, 1998, with the FERC finding that NHEC could
replace PSNH power with purchases from Qualifying Facilities (83 FERC
Paragraph 61,224) and that NHEC was only required to purchase as much power
as was necessary to serve the needs of its retail customers and that it had
no obligation for those retail customers that left NHEC for competitive
retail service. 83 FERC Paragraph 61,223. PSNH and others filed for and were
granted their rehearing request. On rehearing, the FERC modified its initial
decision and granted recovery to PSNH of the revenues associated with the
demand-related portion of the APRA. 86 FERC Paragraph 61,174 (February 24,
1999). On September 30, 1999, PSNH and NHEC reached a settlement that
resolved all disputes between them concerning the APRA. The settlement was
approved in a letter ruling issued by the FERC on December 23, 1999.






Sullima\edgar\23443.txt

EX-99.4

                                                          EXHIBIT H

                         to Application/Declaration of
                         The Connecticut Light and Power Company
                         Western Massachusetts Electric Company
                         Public Service Company of New Hampshire


                        PROPOSED FORM OF NOTICE

                    (Release No. 35-      ; 70-     )


                              FORM U-1
                    APPLICATION/DECLARATION UNDER THE
                PUBLIC UTILITY HOLDING COMPANY ACT OF 1935

         WITH RESPECT TO THE ISSUANCE OF RATE REDUCTION BONDS
                        AND RELATED TRANSACTIONS



         , 2000

The Connecticut Light and Power Company ("CL&P"), Western Massachusetts
Electric Company ("WMECO"), and Public Service Company of New Hampshire
("PSNH" and, together with CL&P and WMECO, each a "Utility" and collectively
the "Utilities"), each an electric utility subsidiary of Northeast Utilities
("NU"), a public holding company registered under the Public Utility Holding
Company Act of 1935, as amended (the "Act"), have submitted an
application/declaration (the "Application") pursuant to Sections 6(a), 7,
9(a), 10, 12(b), (c), (f) and (g), and 13(b) of the Act and Rules 45(a),
45(b)(4), 46(a), 90 and 91 thereunder.  CL&P is located at 107 Selden Street,
Berlin, Connecticut 06037, WMECO is located at 174 Brush Hill Avenue, West
Springfield, Massachusetts 01090, and PSNH is located at 1000 Elm Street,
Manchester, New Hampshire 03101.

According to the Utilities, the states in which CL&P, WMECO, and PSNH
operate - Connecticut, Massachusetts, and New Hampshire, respectively - have
enacted legislation that restructures the electric industries in such states
by introducing retail competition in electricity generation.  In light of the
transition to the new competitive environment, electric utilities will have
certain "stranded costs" - i.e., costs that would have been recoverable in a
regulated environment but are not expected to be recoverable as a result of
the introduction of competition in the generation market.  To facilitate the
transition, the restructuring statutes contain provisions which permit
electric utilities to recover some or all of these costs through the
collection from consumers of electricity located within the service area of
the electric utility of a non-bypassable special charge (the "Transition
Charge") that is based on the amount of electricity purchased by consumers,
regardless of whether such consumer continues to purchase electricity from
that electric utility.  The restructuring statutes each contain provisions
(such provisions, collectively, the "Securitization Acts") that permit
electric utilities to securitize a portion of the Transition Charge (such
portion, the "RRB Charge") to facilitate electric industry restructuring.
Pursuant to the Securitization Acts, electric utilities may petition the
state public utilities commission for an order authorizing and setting forth
the details of the securitization transaction (such order, a "Financing
Order").  The Utilities have each applied for a Financing Order from the
appropriate state public utilities commission.  The structure of the
transactions for each Utility will be substantially similar and will
generally follow one of two formats.

The Utilities state that under the first format, the Utility will cause
the organization of one or more bankruptcy remote, wholly-owned special
purpose entities, each of which is expected to be a Delaware limited
liability company (each an "SPE").  Pursuant to the Securitization Acts, the
right to collect the RRB Charge is established as a separate property right
(the "RRB Property"), and the SPE is authorized to acquire RRB Property and
to issue rate reduction bonds ("RRBs").  The Utility will contribute as
equity to the SPE cash equal to at least 0.50% of the initial principal
balance of RRBs issued with respect to such SPE.  It is anticipated that the
SPE will enter into an administration agreement with the Utility, pursuant to
which the Utility shall perform administrative services and provide
facilities for the SPE.  Under such administration agreement, the Utility
will be entitled to receive an administration fee for its provision of such
services and facilities.  Although this fee is expected to approximate each
Utility's estimate of the actual cost of providing these services and
facilities, the Utilities cannot be certain that this fee will meet the "at
cost" requirements of Section 13(b) of the Act and Rules 90 and 91
thereunder.  Accordingly, the Utilities have requested an exemption from
these requirements.

The Utility will sell the RRB Property to an SPE for an amount equal to
the issue price of the RRBs less any transaction costs paid by the SPE from
the proceeds of the RRBs.  It is expected that the transfer will constitute a
true sale for bankruptcy and commercial law purposes, and therefore the RRB
Property will remain isolated from the Utility's revenues and assets.  The
SPE will issue RRBs to underwriters.  Such underwriters in turn will sell the
RRBs to public investors.  Each Utility presently expects that the following
principal amount of RRBs will be issued on its behalf on or before August 31,
2005:  CL&P - not to exceed $1.489 billion; WMECO - not to exceed $303
million; and PSNH - not to exceed $725 million.

The RRBs will be in the form of promissory notes of the SPE.  The RRBs
will be nonrecourse to the Utility but will be secured by all of the assets
of the SPE, including the RRB Property.  The RRBs will be issued in one or
more series.  Each series of RRBs may be offered in one or more classes, each
expected to have a different principal amount, term, interest rate, and
amortization schedule.  The Utilities also expect that the RRBs will have
legal maturities not longer than 15 years and that the longest-term RRBs will
have scheduled maturities that are at least 6 months earlier.  Other terms
and characteristics of the RRBs will be determined at the time of issuance
based on then-current market conditions.  The SPE may enter into swap
agreements or other hedging arrangements solely to permit the issuance of
variable rate RRBs.  The proposed use of the proceeds from all of the
restructuring transactions is the subject of a previous proceeding under the
Act.  See Northeast Utilities, et al., HCAR No. 27147 (March 7, 2000) (File
No. 70-9541).

The Utilities state that on behalf of the SPE, the Utility will act
initially as the servicer for the RRB Property and will be responsible for
calculating, billing, collecting, and remitting the RRB Charge.  As initial
servicer, the Utility will be entitled to receive a servicing fee for its
servicing activities and reimbursement for certain of its expenses.  Although
this fee is expected to approximate each Utility's estimate of the actual
cost of providing these services, the Utilities cannot be certain that this
fee will meet the "at cost" requirements of Section 13(b) of the Act and
Rules 90 and 91 thereunder.  Accordingly, the Utilities have requested an
exemption from these requirements.

The RRB Charge will be established at a level (or at different levels
during specified periods over the life of RRBs) intended to (i) provide for
the full recovery of payments of interest and principal on RRBs, in
accordance with the expected amortization schedule determined at the time of
offering, (ii) provide credit enhancement, including any liquidity reserves
and an amount for overcollateralization, and (iii) provide for any related
fees, costs and expenses.  The Utilities state that such
overcollateralization amount will eventually reach at least 0.50% of the
initial principal amount of the RRBs, and will be collected ratably over the
expected term of the RRBs.

The Financing Order is expected to provide for the RRB Charge to be
adjusted by a true-up mechanism at least annually to keep actual principal
amortization in line with the expected amortization schedule.  Other forms of
credit enhancement customary for securitization transactions also might be
used, such as a liquidity reserve, debt service reserve fund, bank letter of
credit, or surety bond or similar insurance policy.

The Utilities state that the alternative format that one or more of the
Utilities might follow with respect to the proposed transactions is the same
as the first format in most respects.  However, under the second format,
instead of issuing RRBs to capital market investors, the SPE will issue
promissory notes (the "SPE Debt Securities") to a governmentally-sponsored
trust established by one or more agencies of the state in which the Utility
operates (the "Trust").  The SPE Debt Securities will be secured by the same
assets of the SPE that the RRBs would be secured by under the first format.
The Trust will issue to underwriters RRBs in aggregate principal amount equal
to the aggregate principal amount of the SPE Debt Securities.  Such
underwriters in turn will sell the RRBs to public investors.  The RRBs will
be in the form of pass-through certificates representing beneficial ownership
interests in the SPE Debt Securities held by the Trust.  Each class of each
series of RRBs will represent fractional undivided beneficial interests in a
class of a series of SPE Debt Securities held by the Trust and the proceeds
thereof.  Therefore, each class of RRBs will have terms and characteristics
that are substantially identical to the corresponding class of SPE Debt
Securities.  The SPE or the Trust may enter into swap agreements or other
hedging arrangements solely to permit the issuance of variable rate RRBs.  In
such case, the RRBs would also represent beneficial ownership interests in
those agreements or arrangements.

The Utilities state that they intend to request the Commission's
approval of all transactions described in the Application, whether under
sections of the Act and the rules thereunder enumerated therein or otherwise.

The Application is available for public inspection through the
Commission's Branch of Public Reference.  Interested persons wishing to
comment or request a hearing on the Application should submit their views in
writing by            , 2000, to the Secretary, Securities and Exchange
Commission, Washington, D.C. 20549-0609, and serve a copy on the Utilities at
the addresses specified above.  Proof of service (by affidavit or, in the
case of an attorney at law, by certificate) should be filed with the request.
Any request for hearing should identify specifically the issues of facts or
law that are disputed.  A person who so requests will be notified of any
hearing, if ordered, and will receive a copy of any notice or order issued in
this matter.  After said date, the Application, as filed or as it may be
amended, may be granted and/or permitted to become effective.

For the Commission by the Division of Investment Management, under
delegated authority.

Secretary