NEW ENGLAND ELECTRIC SYSTEM, U-1/A, 2000-03-28

NEW ENGLAND ELECTRIC SYSTEM
U-1/A, 2000-03-28
ELECTRIC SERVICES

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As filed with the Securities and Exchange Commission on March 28, 2000

File No. 70-9537

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM U-1
_________________________________________

AMENDMENT NO. 3 TO FORM U-1
APPLICATION/DECLARATION
UNDER
THE PUBLIC UTILITY HOLDING COMPANY ACT OF 1935
____________________________________________________

National Grid USA Eastern Utilities Associates
Massachusetts Electric Company Blackstone Valley Electric Company
Granite State Electric Company Eastern Edison Company
The Narragansett Electric Company Montaup Electric Company
Nantucket Electric Company Newport Electric Corporation
New England Power Company 750 West Center Street
New England Hydro-Transmission West Bridgewater, MA 02379
Corporation
New England Hydro-Transmission
Electric Company
New England Electric Transmission
Corporation
Research Drive LLC
New England Power Service Company
New England Energy Incorporated
25 Research Drive
Westborough, MA 01582

National Grid Group plc
National Grid (US) Holdings Limited
National Grid (US) Investments
National Grid House
Kirby Corner Road
Coventry CV4 8JY
United Kingdom

National Grid (Ireland) 1 Limited
National Grid (Ireland) 2 Limited
8-10 rue Mathias Hardt
BP39, L 2010
Luxembourg

National Grid General Partnership
10th Floor
Oliver Building
2 Oliver Street
Boston, MA 02109

(Name of companies and top registered holding company parents filing
this statement and addresses of principal executive offices)
__________________________________________________________________

Michael E. Jesanis Donald G. Pardus
Kirk L. Ramsauer Clifford J. Hebert, Jr.
National Grid USA Eastern Utilities Associates
25 Research Drive 750 West Center Street
Westborough, MA 01582 West Bridgewater, MA 02379

(Name and addresses of agents for service)
__________________________________

The Commission also is requested to send copies of any communications
in connection with this matter to:

Clifford M. Naeve, Esq. Arthur I. Anderson, P.C.
Judith A. Center, Esq. David A. Fazzone, P.C.
W. Mason Emnett, Esq. Amy J. Gould, Esq.
William C. Weeden McDermott, Will & Emery
Skadden, Arps, Slate, Meagher 28 State Street
& Flom LLP Boston, MA 02109-1775
1440 New York Avenue, N.W.
Washington, D.C. 20005

National Grid USA, a Delaware corporation and a registered public
utility holding company, and Eastern Utilities Associates, a registered
public utility holding company organized under a Declaration of Trust in
the Commonwealth of Massachusetts, hereby amend their
Application/Declaration on Form U-1 in File No. 70-9537 as follows:

1. By filing the following exhibit:

A. Exhibits

D-3.B Order of the RIPUC (to be filed by amendment)

Pursuant to the requirements of the Public Utility Holding Company Act
of 1935, the undersigned Applicants have caused this pre-effective
Amendment No. 3 to the Application/Declaration in File No. 70-9537 to be
signed on their behalf by the undersigned thereunto duly authorized.

NATIONAL GRID USA
(formerly New England Electric System)

By: /s/ Kirk L. Ramsauer Date: March 27, 2000
-----------------------------------
Title: Deputy General Counsel

NATIONAL GRID GROUP, PLC

By: /s/ Clifford M. G. Carlton Date: March 27, 2000
-----------------------------------
Title: Business Development Manager - Reg.

EASTERN UTILITIES ASSOCIATES*

By: /s/ Clifford J. Hebert, Jr. Date: March __, 2000
----------------------------------
Title: Treasurer

*The name "Eastern Utilities Associates" is the designation of the Trustees
of EUA for the time being in their collective capacity but not personally,
under a Declaration of Trust dated April 2, 1928, as amended, a copy of
which amended Declaration of Trust has been filed in the office of the
Secretary of The Commonwealth of Massachusetts and elsewhere as required by
law; and all persons dealing with EUA must look solely to the trust
property for the enforcement of any claim against EUA, as neither the
Trustees nor the officers or shareholders of EUA assume any personal
liability for obligations entered into on behalf of EUA.

EXHIBIT D-3.B

STATE OF RHODE ISLAND AND PROVIDENCE PLANTATIONS

PUBLIC UTILITIES COMMISSION

IN RE: CONSOLIDATION AND ADJUSTMENT OF RATES FOR
o NARRAGANSETT ELECTRIC COMPANY
o BLACKSTONE VALLEY ELECTRIC COMPANY
o NEWPORT ELECTRIC CORPORATION

DOCKET NO. 2930

REPORT AND ORDER

This proceeding was commenced on May 20, 1999 with the filing by
Narragansett Electric Company ("Narragansett"), the Rhode Island operating
subsidiary of the New England Electric System ("NEES"), and Blackstone
Valley Electric Corporation ("BVE") and Newport Electric Corporation
("Newport"), the Rhode Island operating subsidiaries of Eastern Utilities
Associates ("EUA"), of a proposed rate plan relating to the consolidation
of BVE, Newport and Narragansett in connection with the merger of their
respective parent companies, EUA and NEES.(1) The proposed merger of BVE,
Newport and Narragansett (collectively, the "merged Company") was approved
by the Division of Public Utilities and Carriers ("Division") on February
25, 2000. The filing before the Commission is for approval of a rate
consolidation plan for the merged Company, which will have approximately
one-half million customers, distributed as follows:

Customers Percent(2)
--------- -------
Narragansett 336,000 74%
BVE 87,000 19%
Newport 33,600 7%
-------- ------
456,600 100%
======= ===

- ----------
(1) Filing letter dated May 20, 2000 (Filing Letter).
(2) Ex. AG-1, p. 14.

I. TRAVEL OF THE CASE.

A. ORIGINAL RATE PLAN FILING.

On May 20, 1999, Narragansett filed the testimony of Mr. Michael
E. Jesanis,(3) Mr. Robert G. Powderly,(4) Mr. Lawrence J. Reilly,(5) Mr.
David M. Webster,(6) Mr. James Molloy,(7) Mr. James J. Bonner, Jr.,(8) Mr.
David J. Hoffman,(9) and Mr. Richard J. Levin(10) in support of a proposed
rate plan for the merged Company (the "Original Rate Plan Filing"). This
Rate Plan Filing, which would become effective within 120 days of the
closing of the EUA-NEES merger or April 1, 2000, whichever occurred
later,(11) sought approval to implement (i) a single set of distribution
rates for the merged Company(12) that would be frozen through 2004(13) and
produce an annual rate reduction of approximately $5.4 million,(14) (ii)
the recovery of additional annual depreciation expenses for the merged
Company of approximately $2.8 million through a rate increase of $0.039 per
kWh beginning January 1, 2001,(15) (iii) the recovery of approximately $754
million of acquisition and transaction costs and expenditures incurred by
(a) National Grid Group, plc, in connection with its acquisition of NEES,
and (b) NEES in connection with its acquisition of EUA,(16) and (iv) the
consolidation of the accounting for certain utility assets and liabilities
which are closely monitored by the Commission for ratemaking purposes.(17)

- ----------------
(3) Narr. Ex. 2.
(4) Id.
(5) Id.
(6) Id.
(7) Narr. Ex. 3.
(8) Id.
(9) Narr. Ex. 4.
(10) Id.
(11) Narr. Ex. 2, p. 13 (lower right).
(12) Id. These distribution rates would consist of Narragansett's existing
rates modified to include an additional charge of $0.00661 per kWh
for Newport customers. Narr. Ex. 2 at p. 14; Narr. Ex. 3 at p. 39.
(13) Id.
(14) Id.
(15) Narr. Ex. 2, p. 192 (lower right).
(16) Narr. Ex. 2, p. 72 (lower right); Ex. TEC-RI 1-35.
(17) Narr. Ex. 2, pp. 46-48 (lower right).

Motions to intervene in this proceeding were filed by The Energy
Council of Rhode Island ("TEC-RI"), the United States Department of the
Navy ("Navy"), National Grid Group, plc ("National Grid"), and the Rhode
Island Attorney General ("Attorney General"), and were subsequently granted
by the Commission.

B. COST OF SERVICE FILING.

On July 13, 1999, the Commission ruled that the Company's Original
Rate Plan Filing did not comply with the Part 2 Filing Requirements of the
Commission's Rules of Practice and Procedure in that the Filing did not
contain the requisite cost of service information. On September 16, 1999,
Narragansett filed a consolidated cost of service for the rate year 2000
("Cost of Service Filing") which indicated a revenue excess or (deficiency)
for each company as follows:(18)

Excess Company
Company (Deficiency)
------- --------------
Narragansett ($11,265,000)
BVE ($ 125,000)
Newport $ 1,308,000
------------
Total Revenue Deficiency ($10,081,000)
============
- --------
(18) Narr. Ex. 8 at p. 31 (lower right).

C. TESTIMONY OF OTHER PARTIES.

In response to the Original Rate Plan Filing, on September 27,
1999, the Navy filed the testimony of Dr. Allan Rosenberg,(19) on October
29, 1999, TEC-RI filed a statement of position, and on October 31, 1999,
the Division filed the testimony of Mr. David Effron(20) and Dr. John
Stutz.(21) On November 19, 1999, the Division filed additional testimony of
Mr. Effron(22) and Dr. Stutz(23) in response to the Cost of Service Filing.
The Division's witnesses presented testimony supporting a combined revenue
excess of approximately $10 million, as follows:(24)

Excess
Company Revenues
------- -----------
Narragansett $ 5,794,000
BVE $ 2,983,000
Newport $ 2,685,000
------------
(Less: Increased depreciation) ($ 1,051,000)

Total Excess Revenues $10,411,000
===========
- -------------------
(19) Ex. Navy-1.
(20) Ex. Division-3.
(21) Ex. Division-1.
(22) Ex. Division-4.
(23) Ex. Division-2.
(24) Ex. Division-4, p. 26.

On November 19, 1999, the Attorney General filed the testimony of
Mr. Bruce R. Oliver,(25) Ms. Andrea C. Crane(26) and Mr. Richard W.
LeLash(27) in response to both the Original Rate Plan Filing and the Cost
of Service Filing. The Attorney General's witnesses presented testimony
supporting a combined revenue excess of $13.3 million.(28) On the same day,
the Navy filed the testimony of Dr. Allan Rosenberg in response to the Cost
of Service Filing.(29)

- ----------
(25) Ex. AG-1.
(26) Ex. AG-3.
(27) Ex. AG-2.
(28) Ex. AG-1, pp. 89-90.
(29) Ex. Navy-3.

D. SIMPLIFIED RATE PLAN.

On December 7, 1999, Narragansett filed the rebuttal testimony of
Mr. Michael E. Jesanis,(30) Mr. Michael D. Laflamme,(31) Mr. Augustine
Camara,(32) Mr. Charles Olson,(33) and Mr. James M. Molloy.(34) In its
rebuttal testimony, Narragansett modified the Original Rate Plan Filing and
presented a "Simplified Rate Plan." The Simplified Rate Plan requested
approval to implement (i) a single set of rates for the merged Company that
would produce an annual rate reduction of approximately $9.3 million,(35)
(ii) the recovery of approximately $113 million of acquisition and
transaction costs and expenditures incurred by NEES in connection with its
acquisition of EUA,(36) and (iii) the consolidation of the accounting for
certain assets and liabilities which are closely monitored by the
Commission for ratemaking purposes. The rebuttal testimony included a
modified cost of service that now indicated a combined revenue excess for
the companies of $4.2 million:(37)

Company Excess Revenues
------- ---------------
Narragansett $ 234,000
BVE $2,631,000
Newport $1,350,000
----------
Total Revenue Excess $4,215,000
==========

Narragansett further proposed to defer filing of a fully allocated
cost of service study for the merged Company until after the merger.

- --------
(30) Narr. Ex. 12.
(31) Id.
(32) Id.
(33) Id.
(34) Narr. Ex. 13.
(35) Narr. Ex. 12, pp. 14-17 (lower right).
(36) Id.
(37) Narr. Ex. 12 at p. 75 (lower right).

E. FULLY ALLOCATED COST OF SERVICE FILING.

At an open meeting on December 13, 1999, the Commission ordered
Narragansett to submit forthwith a fully allocated cost of service study
using the modified cost of service filed with the Simplified Rate Plan. On
January 28, 2000, a fully allocated cost of service study was filed with
the Commission.

F. PUBLIC COMMENT.

The Commission traveled to the following locations and conducted
duly noticed public hearings for the purpose of accepting public comments
on the Company's filing:

November 2, 1999 Warwick City Hall, Warwick, RI
November 9, 1999 Pawtucket City Hall, Pawtucket, RI
November 15, 1999 Newport City Hall, Newport, RI

On November 17, 1999, an additional public hearing for the same purpose
commenced at 10:00am in the Commission's hearing room located at 100 Orange
Street in Providence.

II. UNCONTESTED STIPULATION AND SETTLEMENT.

On January 31, 2000, a Stipulation and Settlement entered into
between Narragansett, BVE and Newport and the Division, the Attorney
General, and the Navy, regarding rates for the merged Company, was filed
with the Commission. On February 9, 2000, an Amended Stipulation and
Settlement, adding TEC-RI as a party and containing certain other changes,
was filed with the Commission. Public hearings on the Amended Stipulation
and Settlement were conducted in the hearing room of the Commission at 100
Orange Street in Providence on February 11, 15, 18 and 29, 2000. The
following appearances were entered:

FOR THE COMPANIES Ronald T. Gerwatowski, Esq.
David A. Fazzone, Esq.
David A. Fazzone, PC
McDermott, Will & Emery

FOR THE DIVISION Elizabeth A. Kelleher, Esq.
Special Assistant Attorney General

FOR THE ATTORNEY GENERAL Paul J. Roberti, Esq.
Assistant Attorney General

FOR TEC-RI Andrew J. Newman, Esq.
Rubin and Rudman, LLP

FOR THE NAVY Audrey Van Dyke, Esq.

FOR NATIONAL GRID Patricia French, Esq.
LeBoeuf, Lamb, Green & MacRae, LLP

FOR THE COMMISSION Lindsay A. Johnson, Esq.

Following the conclusion of the hearings, a Second Amended
Stipulation and Settlement, containing a number of changes in response to
concerns raised by the Commission during the hearings, was filed with the
Commission on March 3, 2000. The Navy was not a party to the Second Amended
Stipulation and Settlement, having withdrawn from the settlement following
the hearings. However, by letter dated March 2, 2000 to Narragansett, the
Navy indicated that it would not object to the approval of the settlement
by the Commission. A Third Amended Stipulation and Settlement dated March
14, 2000, adding National Grid as a party and containing certain final
changes, was subsequently filed with the Commission for approval (the
"Settlement").(38)

The Settlement produces an initial annual revenue reduction in the
amount of $13.1 million(39) More specifically, the Settlement provides
that: (i) following the merger, Blackstone and Newport customers will be
billed at Narragansett's rates; (ii) the merged Company's revenues will be
reduced by an annual amount of $2.7 million;(40) (iii) the merged Company's
rates, subject to certain conditions,(41) will be frozen through December
31, 2004;(42) and (iv) to the extent that the Company can demonstrate that
its total post-merger cost of service has been reduced on an ongoing basis,
the merged Company will be allowed to retain a share of the merger savings
following the rate freeze period, as summarized below and more fully
described in the Settlement.

- -------------
(38) A copy of the Third Amended Stipulation and Settlement dated March
14, 2000 is attached as Appendix A hereto and incorporated by
reference herein. Notwithstanding the description of the Settlement
contained in this Report and Order, the terms and provisions
contained in the Settlement are controlling. References herein to
Settlement page numbers refer to the numbers on the lower right-hand
page corner.
(39) Settlement, p. 4 (lower right). See pp. 10-11 for an analysis of the
revenue reduction.
(40) Ibid.at p. 5 (lower right).
(41) Settlement, pp. 11-13 (lower right). The conditions are that the
rates could be increased if inflation exceeds 4% during the period of
the rate freeze or if Federal or State-initiated cost changes cause a
change in revenue requirements by more than $750,000 and $375,000,
respectively.
(42) Settlement, p. 10, (lower right).

Following the rate freeze period, the merged Company's revenue
requirements will continue to be governed by traditional cost-of-service
ratemaking principles, with certain modifications. In particular, the
merged Company will be permitted to include one-half of any proven merger
savings, as more specifically defined by the Settlement, in future cost of
service rate cases through the year 2019,(43) but only in the event that
either (i) the percentage increase in rates is less than the cumulative
amount of 1.9% per year through 2009 and 80% of the cumulative annual
change in the Gross Domestic Product Implicit Price Deflator(44) ("GDPIPD")
from 2010 through 2019,(45) or (ii) the merged Company proves the continued
existence of the merger savings.46 Notwithstanding the foregoing, however,
if the percentage increase in rates is greater than the cumulative change
in the applicable index referred to in clause (i) above,(47) the portion of
the shared savings that caused the applicable index to be exceeded will be
excluded from the merged Company's cost of service, unless such excess is
due to cost increases caused by Federal and/or State-initiated cost changes
or regulatory cost reallocations, as defined in the Settlement.(48) In the
latter case, the merged Company must prove the continued existence of
merger savings in order to continue recovering its savings share.(49)

In addition, in the event that the Company's actual earnings
exceed the 10.5% rate of return on equity allowed under the Settlement,(50)
the merged Company will be required to refund a portion of the excess
earnings.(51)

- --------------
(43) Ibid., pp. 16-27 (lower right).
(44) Tr. 2/15/00, p. 34.
(45) Settlement, pp. 16-27 (lower right).
(46) Id.
(47) The growth in the GDPIPD index is measured from the year 2000.
Settlement, pp. 26, 96 (lower right).
(48) Id.
(49) Id.
(50) Settlement, pp. 29-32 (lower right).
(51) During the period of the rate freeze the Company is required to
refund 50% of return on equity earnings between 12% and 13% and 75%
of earnings in excess of 13%. For the post-rate freeze period the
Company is required to refund 50% of the first 1% of earnings over
the allowed return on equity and 75% of any earnings in excess
thereof.

The Settlement also provides for:

1. The expansion of the availability of the Low Income Rate A-60
to include all customers who are eligible for assistance
through the State's Low Income Home Energy Assistance Program
("LIHEAP") program.(52)

2. The adoption of service quality performance standards with
financial penalties in the event that such standards are not
maintained.(53)

3. The prohibition on recovery in rates by the merged Company of
"golden parachute" and severance payments.(54)

4. The implementation of higher depreciation rates and deferred
tax accounting for the cost of removal.(55)

5. The retention by Narragansett of a $17.5 million lump sum
credit to its Contract Termination Charge account to fund a
portion of the deficiency in Narragansett's deferred tax
reserve.(56)

6. The creation of an Environmental Response Fund to satisfy
remedial and clean-up obligations of Narragansett, BVE and
Newport arising from the ownership and/or operation of
manufactured gas plants and sites associated with the
operation and disposal activities from such gas plants.(57)

7. The consolidation of the companies' transmission rates in two
steps. For the year 2000, a separate transmission adjustment
factor shall be calculated for customers in the Newport, BVE,
and Narragansett service territories to continue the present
allocation of transmission costs currently assigned to each
company. Beginning in the year 2001, however, the merged
Company will eliminate these zonal adjustment factors and
apply one transmission adjustment factor for all customers.

8. The phase-in of uniform transition charges.

- ----------
(52) Settlement, p. 40 (lower right).
(53) Ibid., pp. 39-40; 108-116 (lower right).
(54) Ibid., pp. 18, 39 (lower right).
(55) Ibid., p. 28 (lower right).
(56) Id.
(57) Ibid., pp. 33-35 (lower right).

The Settlement proposes six types of rate changes to implement the
$13.1 million revenue reduction.(58) First, the application of
Narragansett's rates to BVE and Newport customers will produce annual
customer savings totaling $8 million.(59) Second, the rate for the Navy
will be reduced to produce annual savings of $734,000.(60) Third, the
expansion of the availability of the Low-Income Rate A-60 will create
$600,000 of savings.(61) Fourth, at least through 2004, all customers would
receive a uniform "Settlement Credit" of $0.00038 per kWh(62) in order to
generate an additional $2.7 million of savings.(63) Fifth, credits totaling
$400,000 would be applied to Newport and BVE customers' bills through the
end of 2004 to ensure that no customers receive rate increases. Sixth, a
$700,000 annual reduction in the contract termination charge expenses to
BVE and Newport customers.

- -----------------
(58) Ibid., p. 4 (lower right).
(59) Id.
(60) Id..
(61) Ibid., p. 5 (lower right).
(62) Joint Ex. 3, Ex. 2, Rate Cover Sheets.
(63) Settlement, p. 5 (lower right).

III. COMMISSION FINDINGS.

At an open meeting of the Commission on March 14, 2000, the Third
Amended Stipulation and Settlement dated March 14, 2000 was unanimously
approved based upon the Commission's finding that the parties presented
substantial evidence that the Settlement is in the public interest because
it: (i) is the product of serious bargaining among capable, knowledgeable
parties; (ii) benefits ratepayers and the public interest; and (iii) does
not violate any important regulatory principle or practice. In approving
the Settlement, however, the Commission will not give up any authority the
Legislature has delegated to the Commission to protect the public against
improper and unreasonable rates.

Generally, ratemaking constitutes the exercise of legislative
powers delegated to the Commission by the Legislature and the Commission's
findings are not binding on future Commissions. The Commission approves the
Settlement subject to its own, as well as every future Commission's,
ongoing obligation and right to review and, where required, modify rates to
protect the public against improper and unreasonable rates. The
Commission's obligation arises from the Legislative mandate that the
Commission periodically review and hold public hearings respecting public
utility rates.(64) This review is required of all proposed rate changes and
also in the absence of any proposed rate changes.(65) It is the
Commission's view that this Legislative mandate gives the Commission an
indefeasible(66) right to modify rates as required to protect the public in
accordance with the intent of the statute. Accordingly, the Commission's
approval of this Settlement and the agreed-upon rates is not binding upon a
future Commission in any future investigation of Narragansett's rates, to
the extent modifications of this Settlement are consistent with the
Commission's ongoing obligation to protect the public against improper and
unreasonable rates.

- -----------
(64) R.I.G.L.ss.39-1-1(c).
(65) R.I.G.L.ss.39-3-11; see also In re Island Hi-Speed Ferry, LLC,
RI Sup. Ct. slip op. at p.6 (issued Feb. 21, 2000).
(66) The rule-making power of any administrative body may not abrogate
state law dealing with the same subject. Reback et al. v. Rhode
Island Board of Regents, 560 A.2d 357, 358.

There is one rate matter that is not included in the Settlement.
This matter arises from the fact that Narragansett, BVE and Newport each
has a similar tariff that allows for the refund or recovery, as
appropriate, of any over- or under-collection of the cost of wholesale
Standard Offer service.(67) Narragansett proposes that, following the merger,
all customers would be billed under the provisions of its Standard Offer
Adjustment Provision. There is, however, one significant provision in the
BVE and Newport tariffs that is not contained in the Narragansett tariff:

Notwithstanding the foregoing, the Company may not recover,
without full disclosure and the express approval of the
Commission, any cost of Standard Offer Service in excess of the
costs billable under the Settlement Agreement dated October 17,
1997.(68)

- ----------
(67) See Order No. 15521, Docket No. 2651, dated July 10, 1998, p.18.
(68) Order No. 15756, Docket No. 2834, dated December 31, 1998, at p. 14.

This provision arose out of the Commission's ongoing concern with
the terms of BVE and Newport's Standard Offer supplier contracts. In
essence, the Commission's concern was that BVE and Newport had not,
consistent with prior representations, required Standard Offer wholesale
suppliers to "deliver a performance surety securing the suppliers full
responsibility."(69) The Commission found that the security provisions did
not "meet reasonable commercial standards because the quality and
reliability of service may be compromised, and/or additional costs could be
incurred in the event of a supplier default."(70) BVE and Newport
represented to the Commission, however, that any costs arising from the
default of a supplier would not be recoverable from ratepayers:

The financial consequences to ratepayers arising from these issues
. . . will be mitigated by the fact that the Companies have
represented to the Commission that costs arising from the default
of a supplier are not recoverable from ratepayers and that
negotiated cost increases . . . are recoverable only with the
Commission's express approval. The Commission believes that these
facts should be made clear in the Companies' tariffs. In addition,
the Commission finds that the tariff language should specify the
rights of all parties to examine the facts surrounding the
acquisition of power supply and to contest the Companies' rights
to recover any resulting costs.(71)

The merger of BVE, Newport and Narragansett does not change the
extent to which costs incurred under BVE and Newport's Standard Offer power
contracts are recoverable. Narragansett is simply stepping into the shoes
of BVE and Newport with respect thereto.(72) Consequently, the Commission
finds that the following modified tariff language should be inserted in
Narragansett's Standard Offer Adjustment Provision:(73)

- -------------
(69) Ibid. p. 11.
(70) Ibid., p. 13.
(71) Ibid., pp. 13-14.
(72) It should be noted that Mr. Jesanis stated that any commitment made
by BVE and Newport would be honored by Narragansett. Tr. 2/15/00, p.
110.
(73) The addition of this provision was agreed to by Narragansett's
Counsel by letter dated March 6, 2000.
(74) Order No. 15756, Docket No. 2834, dated December 31, 1998, at p. 14,
as revised per letter from Narragansett's Counsel dated March 6,
2000.

Accordingly, it is:

(16200) ORDERED:

1. That the rate plan filing filed on May 20, 1999 relating to the
consolidation of Narragansett, BVE and Newport is hereby denied and
dismissed.

2. That Third Amended Stipulation and Settlement dated March 14, 2000 is
hereby approved.

3. That Narragansett's proposed Standard Offer Adjustment Provision
shall be modified to include the following at the end of the proposed
Provision:

4. That the Company shall file compliance tariffs consistent with the
terms of the Third Amended Stipulation and Settlement to become
effective on the later of: (i) the first day of the month following
the closing of the merger, or (ii) the first day of the month
following the completion of all modifications to the customer billing
and metering systems necessary for the consolidation of rates.

5. That the Company shall act in accordance with all other terms and
conditions imposed by the Third Amended Stipulation and Settlement
and this Report and Order.

EFFECTIVE AT PROVIDENCE, RHODE ISLAND PURSUANT TO AN OPEN MEETING
DECISION ON MARCH 14, 2000. WRITTEN ORDER ISSUED MARCH 24, 2000.

PUBLIC UTILITIES COMMISSION

-------------------------------
Kate F. Racine, Commissioner

--------------------------------
Brenda K. Gaynor, Commissioner

APPENDIX A

STATE OF RHODE ISLAND AND PROVIDENCE PLANTATIONS
RHODE ISLAND PUBLIC UTILITIES COMMISSION

- -------------------------------------
)
Narragansett Electric Company ) R.I.P.U.C. No. 2930
Blackstone Valley Electric Company )
Newport Electric Corporation )
- -------------------------------------

THIRD AMENDED STIPULATION AND SETTLEMENT

The Narragansett Electric Company ("Narragansett" or "Company"),
Blackstone Valley Electric Company ("BVE"), and Newport Electric
Corporation ("Newport") (collectively "Companies") enter into this
Stipulation and Settlement ("Settlement") with the Division of Public
Utilities and Carriers ("Division"), the Department of the Attorney General
("Attorney General"), The National Grid Group, plc, and The Energy Council
of Rhode Island ("TEC-RI") (collectively, the "Parties"), to resolve all
issues arising in this Docket 2930.(75)

- ------------
(75) The Department of the Navy is not a party to this agreement, but have
represented that they do not oppose the approval of the Settlement.

1. MERGER OF THE OPERATING COMPANIES

For purposes of this Settlement, it is assumed by the Parties that
Newport and BVE will merge with and into Narragansett. The Attorney General
and TEC-RI agree to support the Petition of the Companies in Division
Docket D-99-12, for authorization to consummate such merger, and the
advocacy section of the Division and the Attorney General agree to withdraw
any opposition to Division approval in that docket. References in this
Settlement to "customers" refer to all customers located in the service
territories of Narragansett, BVE, and Newport, unless expressed otherwise.

2. RATE REDUCTIONS AND RATE DESIGN

(a) As of the Rate Consolidation Date, defined below,
Narragansett shall implement a set of rate reductions
totaling $13.1 million. This set of reductions consists of a
reduction in consolidated distribution rates that are
approximately $12.4 million less than the combined
distribution revenues of the three Companies, plus a
reduction in annual contract termination charge expenses
equal to an initial annualized amount of approximately
$700,000, implemented in the manner described in paragraph
(d) below. The first $8.7 million of the distribution revenue
reduction will be applied to fully consolidate Newport and
BVE distribution rates to Narragansett rates and lower the
current distribution rate of the Department of the Navy rate
by approximately $734,000. The next $400,000 of distribution
revenue reduction will be applied to fund rate design
mechanisms that are intended to "hold harmless" all Newport
and BVE customers from distribution rate increases resulting
from the rate consolidation through December 31, 2004, as
described in Exhibit 1. The next $600,000 will be used to
fund expansion of the low income rate. The remaining amount
of distribution revenue reduction of approximately $2.7
million will be applied as a uniform per kWh "Settlement
Credit" on all customer bills.

(b) Certain of the "hold harmless" rate design mechanisms, as
identified in Exhibit 1, shall expire on December 31, 2004.

(c) The "Settlement Credit" will remain in effect after December
31, 2004 unless the Company has made a filing and showing
with the Commission in 2004 resulting in a Commission finding
that the Company's return on equity was less than 10.5% in
2003 on an historical test year basis, as adjusted to reflect
established Commission ratemaking principles and to
incorporate any other normalizing adjustments as may be
appropriate. However, there will be no adjustments to actual
results to recognize or annualize known and measurable
changes. In the case resulting from such filing, the Company
must meet the same burden of evidentiary proof as occurs in a
cost of service rate case, subject to the usual review of the
Commission and permitted evidentiary challenges by the
Division and other intervenors. No allowance for the
Company's share of savings will be permitted in the
calculation of earnings in this filing. If the Company meets
its burden, the "Settlement Credit" will expire on December
31, 2004. If the "Settlement Credit" does not expire, it
shall remain in effect until new distribution rates are
established through the Company's first cost of service rate
case.

(d) The reduction in contract termination charge expenses will
occur by lowering the return earned on fixed costs in the
contract termination charge formula set forth in the service
agreement between Montaup Electric Company, Blackstone Valley
Electric, and Newport Electric. The return will be lowered to
the same return as earned by New England Power Company in the
contract termination charge formula set forth in the service
agreement between New England Power Company and Narragansett
Electric. An appropriate filing shall be made at FERC to
implement this provision.

3. DEFINITION OF "RATE CONSOLIDATION DATE"

(a) For purposes of this Settlement, the term "Rate Consolidation
Date" refers to the date upon which the terms of this
Settlement shall go into effect, which shall be the last to
occur of the following:

(i) the first cycle of the billing month following the day
that the Companies notify the Commission and the
Parties in writing that all modifications to the
customer billing and metering systems necessary for the
consolidation of rates have been completed;

(ii) the first cycle of the billing month following a
written order by the Division approving the merger of
the operating companies in Docket D-99-12 ("Division
Merger Approval"); or

(iii) the first cycle of the billing month following a
written order by the Commission approving this
Settlement ("Commission Settlement Approval").

(b) Rates going into effect on the Rate Consolidation Date shall
be on a bills rendered basis.

4. MONTHLY CREDITS FOR DELAYED IMPLEMENTATION OF RATE CONSOLIDATION

(a) If Division Merger Approval has been received by February 25,
2000 and Commission Settlement Approval has been received by
March 1, 2000, but the Rate Consolidation Date does not occur
by April 1, 2000, the Companies will provide a credit for the
benefit of customers equal to $1 million per month until the
Rate Consolidation Date occurs, as provided below, beginning
with the month of April. The $1 million credit (net of taxes)
will be applied by reducing the deferred tax deficiency of
BVE and Newport that will otherwise exist following the
merger. For purposes of this Section 4, Division Merger
Approval and Commission Settlement Approval must be through a
written order.

(b) If (i) Division Merger Approval is not received by March 1,
2000, but is received before March 15, 2000 or (ii)
Commission Settlement Approval is not received by March 1,
2000, but is received by March 30, 2000, Narragansett will be
required to provide a credit of $500,000 (net of taxes) for
the first month for a delay in the Rate Consolidation Date
beyond April 1 and $1 million (net of taxes) per month
thereafter.

(c) If either the Division Merger Approval or Commission
Settlement Approval is not received by March 15, 2000 and
March 30, 2000, respectively, Narragansett will be required
to provide a credit of only $500,000 (net of taxes) for each
month for a delay in the Rate Consolidation Date beyond April
1; provided, however, once all necessary regulatory approvals
for the merger of EUA and NEES have been obtained (including
Division Merger Approval, Commission Settlement Approval,
approval of the Massachusetts Department of
Telecommunications and Energy, and the approval by the
Securities and Exchange Commission), the Company will be
required to provide a credit of $1 million per month (net of
taxes) if the Rate Consolidation Date has not been achieved
on the first billing cycle of the month thirty days after
receipt of the final order providing the last outstanding
approval necessary for the merger of EUA and NEES.

(d) For every $500,000 of credits applied pursuant to this
Section to reduce the deferred tax deficiency of BVE and
Newport that will otherwise exist following the merger, the
Company will increase the amount of incremental costs borne
by the Company for the expansion of the low income rate
referenced in Section 20 by $40,000.

5. RATES, TARIFFS, AND TERMS & CONDITIONS FOR SERVICE

(a) The rates reflected on the cover sheets for all of the rates
and tariffs included in Exhibit 2 will take effect for
billings to all customers on and after the Rate Consolidation
Date. The new Narragansett rates G-22 and N-01, as well as
amended tariffs A-32 and A-60, each of which are included in
Exhibit 3, will take effect for billings on and after the
Rate Consolidation Date. All the terms of the other
pre-existing rates referenced in Exhibit 2 shall remain the
same as currently effective for Narragansett. All of
Narragansett's terms and conditions for service which are in
effect as of the Rate Consolidation Date shall apply to all
customers, including terms and conditions for customers and
nonregulated power producers. A copy of the Terms and
Conditions applicable to customers, that will go into effect
on the Rate Consolidation Date, is attached as Exhibit 8,
marked to show changes from those currently in effect. The
effect of the rate consolidation will be to have one set of
rates, tariffs, terms, and conditions applying to all
customers and to terminate all rates, tariffs, terms, and
conditions previously in effect for BVE and Newport.

(b) Customers currently grandfathered on the Company's Auxiliary
Service tariffs shall remain grandfathered on that tariff
through the end of the Rate Freeze Period.

6. DISTRIBUTION RATE FREEZE

(A) RATE FREEZE PERIOD

From the Rate Consolidation Date through the end of calendar year
2004 ("Rate Freeze Period"), the distribution component of Narragansett's
rates reflected in Exhibit 2 shall be frozen, subject only to the exogenous
events defined below ("Exogenous Events").(76) During the Rate Freeze Period,
the Companies will adjust distribution rates by a uniform per kWh factor as
a result of any of the Exogenous Events, subject to subsection (C) below.
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(76) Gross receipts taxes during the Rate Freeze Period shall be directly
reflected on the tariff sheets and customer bills, whether higher or
lower than that which was in effect at the beginning of the Rate
Freeze Period.

(B) EXOGENOUS EVENTS

(1) State Initiated Cost Change: Narragansett shall
adjust its distribution rates (upward or
downward) if the occurrence of a "State
Initiated Cost Change", as defined below, causes
(in the aggregate) a change in the
Narragansett's revenue requirement by more than
$375,000. For purposes of this Settlement, the
term "State Initiated Exogenous Change" shall
mean: (i) the enactment or promulgation of any
new or amended state or local tax laws,
regulations, or precedents governing income,
revenue, sales, franchise, or property taxes or
any new or amended state or locally imposed fees
(but excluding the effects of annual changes in
local property tax rates and revaluations); (ii)
the elimination of any existing state or local
tax or fee obligations; and (iii) any state
legislative or state regulatory mandates which
impose new obligations, duties or undertakings,
or remove existing obligations, duties, or
undertakings which individually decrease or
increase Narragansett's costs.

(2) Federally Initiated Cost Change: Narragansett
shall adjust its distribution rates (upward or
downward) if the occurrence of a "Federally
Initiated Cost Change", as defined below,
causes (in the aggregate) a change in the
Narragansett's revenue requirement by more than
$750,000. For purposes of this Settlement, the
term "Federally Initiated Cost Change" shall
mean: (i) any externally imposed changes in the
federal tax rates, laws, regulations, or
precedents governing income, revenue, or sales
taxes or any changes in federally imposed fees;
and (ii) any federal legislative or federal
regulatory mandates which impose new
obligations, duties or undertakings, or remove
existing obligations, duties, or undertakings
which individually decrease or increase
Narragansett's costs.

(3) Regulatory Cost Reallocation: The distribution
rates reflected in this Settlement during the
Rate Freeze Period are based on the separation
of costs among supply, transmission, and
distribution functions in place on the date of
the Settlement. If a "Regulatory Cost
Reallocation", as defined below, causes a change
in Narragansett's revenue requirement by more
than $500,000, Narragansett will make an
appropriate adjustment to its distribution rates
to reflect such change or allocation. For
purposes of this Settlement, the term
"Regulatory Cost Reallocation" shall mean the
reassignment of costs and/or revenues now
allocated to generation, transmission, or
distribution functions to or away from the
distribution function by the Commission, FERC,
NEPOOL, the ISO or any other official agency
having authority over such matters.

(4) Excessive Inflation: If the average rate of
inflation from January 1, 2000 through 2002,
measured by annual changes in the "Gross
Domestic Product Implicit Price Deflator"
("GDPIPD"), exceeds 4%; or such average annual
rate of inflation from January 1, 2000 through
2003 exceeds 4%, Narragansett will be allowed,
pursuant to the procedure below, an increase in
its distribution revenues in years 2003 and/or
2004, respectively, equal to the amount by which
such average inflation rate exceeds 4%. In
calculating the amount of the allowed increase,
an adjustment to the distribution cost of
service used in the calculation shall be made to
remove depreciation before multiplying the
allowed percentage against distribution revenue.

(1) Procedure. If any of the Exogenous Events
described above occur during the Rate Freeze
Period, Narragansett shall file for adjustments
no later than December 31 of the year in which
the event(s) occurred. If Narragansett has not
made a filing, the Division and other Parties
have the right to make a filing on their own to
open a proceeding if the Division or other
Parties believe an Exogenous Event has occurred
that should result in a rate decrease. Any
adjustments shall be subject to review by the
Commission, and after a public hearing and
approval by the Commission, shall be
implemented for usage on and after April 1 of
the following year (unless suspended by the
Commission) and shall be collected through a
uniform and fully reconciling surcharge or
refund factor applied to all kilowatt-hours
billed under Narragansett's retail delivery
rates. Any such filings are limited to once per
calendar year, provided that any costs incurred
or avoided from such Exogenous Events shall be
deferred for consolidation in the single
filing. However, when accumulated deferred
costs reach $1 million, the total cost shall
accrue interest at the customer deposit rate
from such time until recovered in rates. In
instances where the total accrued costs are
less than $1 million and the effective date of
the adjustment is suspended beyond April 1, the
Company shall be entitled to accrue interest at
the customer deposit rate for the accumulated
deferred costs (even though less than $1
million) from April 1 until cost recovery is
allowed. In any proceeding under this
subsection, the Party claiming that there
should be a rate modification resulting from
the occurrence of an Exogenous Event shall
carry the burden of proving the occurrence and
the cost impact. The Company will file a
certification with the Commission by February 1
of each year during the Rate Freeze Period,
with copies to the Parties, certifying that, to
the best of the Company's knowledge and belief,
there have been no occurrences of Exogenous
Events except as identified in the
certification.

(2) Earnings Limit. If and when the Company makes a
filing seeking an adjustment that increases
rates under this section, if the average
intrastate return on equity of the Company,
calculated using the same methodology as set
forth in Section 11(A) below, for the time
period from January 1, 2000 to the end of the
last quarter prior to the date of the filing for
such adjustment, exceeds 12.00%, the Company
will not be permitted to make a rate adjustment
until the average return has dropped below
12.00%. If and when the average return drops
below 12.00%, the Company may only recover costs
on a prospective basis.

(D) TRADITIONAL COST OF SERVICE RATEMAKING AFTER THE RATE
FREEZE PERIOD

After the Rate Freeze Period, no special adjustments to
distribution rates for Exogenous Events, as described in this
Section, shall be permitted.(77) Except for the expiration of the
Settlement Credit (if applicable) and the expiration of certain of
the "hold harmless" rate design mechanisms referred to in Exhibit
1, distribution rate changes (other than rate changes governed by
Commission- approved reconciliation adjustment provisions) may
occur under traditional cost of service principles, consistent
with Rhode Island law. As such, the Company is permitted to file a
cost of service rate case to change distribution rates for usage
on or after January 1, 2005,(78) if the Company believes it has or
will have a revenue deficiency for the applicable rate year. The
Parties also have the right to file a complaint with the
Commission requesting the Commission require a cost of service
review to reduce distribution rates on or after January 1, 2005 if
the Parties believe that the Company has or will have a revenue
excess. In any cost of service case, whether commenced by a filing
of the Company, a complaint, or on the Commission's initiative,
the Company may include an allowance for its share of savings, to
the extent permitted by Section 8 of this Settlement.

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77 Any Exogenous Event adjustments made during the Rate Freeze
Period will remain in rates through the completion of the Company's
first COS rate case. However, no future adjustments will be
permitted after the Rate Freeze Period.

78 A filing may be made in 2004 to change rates for usage on and
after January 1, 2005.

(E) NON-RATE CHARGES NOT LIMITED BY SETTLEMENT

(1) Other Fees and New Services. The distribution
rate freeze set forth in this Section shall not
preclude Narragansett from proposing to increase
fees relating to line extensions or other
existing fees that are subject to Commission
approval. In addition, the Company is not
precluded from increasing pole attachment fees
and other telecommunication-related fees
referenced in Section 17 below. In addition,
this Settlement does not preclude Narragansett
from proposing new services for customers or
nonregulated power producers for fees, provided
any such fees are approved by the Commission.
All revenue resulting from any increases in such
fees and implementation of new fees shall be
reflected above the line in the calculation of
Narragansett's annual earnings reports (subject
to provisions of Section 17 below).

(2) Terms and Conditions. Nothing in this Settlement
shall preclude Narragansett from proposing
changes to the provisions of its terms and
conditions for customers and nonregulated power
suppliers or the non-rate related provisions of
its rates and tariffs.

7. EXCLUSION OF MERGER ACQUISITION COSTS FROM RATES; IMPUTED CAPITAL
STRUCTURE

(A) EXCLUSION

For purposes of cost of service and ratemaking, (1) the
amortization of acquisition premiums and transaction costs from
the NEES/EUA and NEES/National Grid mergers shall be excluded from
rates, and (2) all unamortized acquisition premiums and
transaction costs shall be excluded from Narragansett's rate base
and Narragansett's rate base shall continue to be based on
original cost of plant devoted to public service less
depreciation. For purposes of this paragraph, the term
"transaction costs" includes all employee separation costs
resulting from the mergers.

(B) IMPUTED CAPITAL STRUCTURE

Because the Company's actual equity as shown for financial
accounting purposes will be affected by Narragansett's recording
of an acquisition premium and transaction costs on its financial
statements as a result of both the NEES/EUA and NEES/National Grid
mergers, the Company agrees to use an imputed capital structure
for ratemaking purposes until the end of the Rate Freeze Period or
the conclusion of the first COS rate case, which ever occurs
later. Until the Commission issues an order establishing new rates
at the conclusion of the Company's first COS rate case, the
Company shall use the imputed capital structure and associated
cost rates shown below to calculate its return and income taxes
for ratemaking purposes, including: (i) earnings reports under
Section 11, (ii) savings calculations under Section 8, (iii)
expiration of the Settlement Credit under Section 2(c) and (iv)
the triggers for Exogenous Events under Section 6(C)(2). The
imputed capital structure and costs shall be as follows:

debt 45% 7.81%
preferred 5% 5.20%
common equity 50% 10.50% (79)

All Parties reserve their rights to take any position regarding what the
appropriate capital structure and cost rates should be in any rate case
establishing rates after the Rate Freeze Period.

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79 The 10.5% common equity return imputation applies only for the
savings calculations under Section 8, since the Earnings Reports, the
calculation under Section 2(c), and Exogenous Events triggers require
a calculation of that return.

8. INCENTIVE-BASED MERGER SAVINGS PLAN

A properly structured incentive based rate plan can align the
interests of the Company and its customers by establishing appropriate
incentives to maximize merger related savings for the benefit of the
Company and its customers. To that end, the Parties agree that provable
cost savings achieved by the Company shall be shared between the
Company and customers as described in this section, according to the
savings determination formula, verification mechanisms, and reopener
provisions described below.

(A) SAVINGS PROOF FILED EITHER IN 2002 OR 2003

(1) Filing. The Company will file in 2002 or 2003 a cost
of service ("COS") for either 2001 or 2002 (the
"measurement year"), at its option, using calendar year
cost data on an historic test year basis for the most
recent calendar year. For the purpose of this COS filing,
actual measurement year results will be adjusted to
reflect established Commission ratemaking principles and
to incorporate any other normalizing adjustments as may
be appropriate. However, there will be no adjustments to
actual results to recognize or annualize known and
measurable changes. Any party in the savings proof
proceedings may contend that the measurement year COS
should be adjusted upward or downward based on the
occurrence of any "Exogenous Events" (as defined in
subsections 6(B)(1)(2)&(3)) in order to avoid having the
merger-related savings be artificially inflated or
deflated by such events, with the burden of proof on the
party making the contention.

(2) Imputed Capital Structure and Costs. In the
measurement year COS filing, Narragansett shall use the
capital structure and associated cost rates to calculate
its return and income taxes as provided in Section 7(B).

(3) Measurement of Savings. Achievement of savings shall
be measured by subtracting the distribution measurement
year COS revenue requirement described in (1) above from
the adjusted Benchmark COS. For the purpose of this
section, the adjusted Benchmark COS shall mean, the
"Benchmark COS" ($210,000,000, which amount does not
incorporate the effect of any merger related savings)
escalated by 50% of the change in the "GDPIPD" from 2000
through the measurement year, plus the escalated
Benchmark COS times 30% of the growth in the weather
normalized measurement year KWH sales from the year 2000
KWH sales. For the purpose of this calculation, the year
2000 KWH sales are 7,098,202,000 KWH. Exhibit 4a shows
the formula for measuring savings and provides an
illustrative example of the calculation of savings in
2002 or 2003.

(4) Sharing of Savings. The measurement year COS will not
be used to adjust rates. Rather, its sole purpose will be
to determine the amount of savings that have been
achieved. Fifty percent (50%) of the savings calculated
in (3) above, escalated by 50% of the cumulative change
in the "GDPIPD" until the "Second Savings Verification"
described in subsection (B) below, will be allowed as an
expense in COS filings made to change rates on or after
January 1, 2005 and included in earnings reports for all
years after the Rate Freeze Period until the end of 2019,
subject to the savings verification described in
subsection (B) below and the reopener provisions
described in subsection (C) below.

(5) Burden of Proof. For purposes of this subsection, the
Company must meet the same burden of evidentiary proof as
occurs in a cost of service rate case, subject to the
usual review of the Commission and permitted evidentiary
challenges by the Division and other intervenors.

(B) SECOND SAVINGS VERIFICATION BY 2007.

The Company will be required to verify the existence of
the savings proven in the filing referenced in subsection (A)
above, using the same basic methodology as described therein. This
"second savings proof" will occur in the first COS rate case filed
by the Company that reflects an historic test year that is no less
than two years after the test year used for the first savings
proof. In such second savings proof occurring through a COS rate
case filing, the methodology reflected in Exhibit 4b (which uses
the rate year in the COS filing) shall apply. If the second
savings proof has not occurred by April 30, 2007, the Company will
be required to make a filing by such date solely for purposes of
verifying savings. If the second savings proof does not occur
through a COS rate case, the methodology reflected in Exhibit 4c
shall apply. Fifty percent of the savings proven (not exceeding
that which was proven through subsection (A) above, as escalated)
will be fixed and allowed in each COS through 2019, subject to the
reopener provisions of subsection (C) below. If the savings are
lower than that which was proven in the first savings proof
(escalated as provided in Section 8(A)(4) above), then such lower
value will be used. For purposes of this subsection, the Company
must meet the same burden of evidentiary proof as occurs in a cost
of service rate case, subject to the usual review of the
Commission and permitted evidentiary challenges by the Division
and other intervenors. If the Company files a COS rate case in
2004 to change rates for usage on and after January 1, 2005 and
such case would not otherwise trigger the "Second Savings
Verification", the Parties shall have the option to propose and
the Commission shall have the authority to order that the "Second
Savings Verification" take place in that proceeding.

The savings determined under subsection (A) and (B) above
shall be final and conclusive provided that rates remain below
certain inflation-based thresholds described below. If rates rise
above the thresholds, then the reopener provisions described below
shall apply. The thresholds described below do not establish a
right for the Company to raise its rates to either of the threshold
levels. The thresholds only determine whether the Company may
include a share of the merger savings in any given cost of service
rate case filed after the Rate Freeze Period. The application of
these thresholds is set forth below:

(1) DEFINITIONS

For purposes of this subsection (C), the following terms
shall have the meanings given:

(a) "Revenue Change" is defined as the resulting
change in revenues, for the specified rate year,
produced by a change in distribution rates from the
distribution rates then in effect, but excluding the
following: (i) the increase in distribution rates
resulting from the expiration of the Settlement
Credit at the end of the Rate Freeze Period, if
applicable, (ii) the increase in distribution
revenues resulting from the partial expiration of
"hold harmless rate design" mechanisms after the
Rate Freeze Period, (iii) any increases relating to
the recovery of costs associated with the expansion
of the low income rate, and (iv) 75% of the increase
resulting from a COS rate case filed in 2004, if
any, for rate changes going into effect on or after
January 1, 2005.

(b) "Percentage Revenue Change" is defined as 100
times the Revenue Change divided by the revenues
that would be produced, in the specified rate year,
by the rates then in effect prior to the Revenue
Change.

(d) "Reopener Index" shall be 1.9% per year from
January 1, 2005 through December 31, 2009.
Thereafter, it shall be 80% of the annual change in
the "GDPIPD".

(e) "Cumulative Reopener Index" equals the sum of
the Reopener Indices for each year.

(2) REOPENER THRESHOLDS

(a) REOPENER THRESHOLD (THROUGH 2014): If at the
time of any cost of service rate case filed by the
Companies after 2004 and before 2015, the Cumulative
Percentage Revenue Change exceeds or will exceed the
Cumulative Reopener Index for the years which have
elapsed since December 31, 2004, Narragansett shall
be required to include in its cost of service case
filed with the Commission evidence regarding the
continued existence of savings to Narragansett
resulting from the acquisition of EUA by NEES or the
acquisition by NEES or its parent company of other
utility companies. The parties to this Settlement
will have the right to offer evidence disputing the
presence of such savings. If the Commission
concludes that the savings are less than the amount
included in the cost of service, the savings
included in the cost of service shall be reduced to
the amount determined by the Commission.

(b) "GDPIPD" THRESHOLD (THROUGH 2014): Until the end
of 2014, if at the time of the cost of service
review referred to in subsection (C)(2)(a) above,
the Cumulative Percentage Revenue Change exceeds or
will exceed the cumulative change in the "GDPIPD"
("Line B" in Exhibit 5) from December 31, 1999, the
portion of the shared savings that causes the
applicable index to be exceeded will be excluded
from the cost of service until such time as the
Cumulative Percentage Revenue Change is less than or
equal to the change in the "GDPIPD".(80) However, if
the Company can demonstrate that the reason why the
"GDPIPD" referenced above was exceeded was a result
of cost increases caused by "State Initiated Cost
Changes", "Federally Initiated Cost Changes", or
"Regulatory Cost Reallocations", as defined in
Section 6 above, the Company may be entitled to
prove the continued existence of savings, as
provided in subsection (a) above.

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80 Any portion of the savings below the GDPIPD index is subject to the
Company proving the continued existence of the savings, as provided
in subsection (a).

(c) REOPENER THRESHOLD (AFTER 2014): After 2014, if
the Cumulative Percentage Revenue Change exceeds or
will exceed the Cumulative Reopener Index for the
years that have elapsed since December 31, 2004 as a
result of Revenue Changes going into effect on or
after January 1, 2015, the portion of the shared
savings that causes the index to be exceeded will be
permanently excluded from the cost of service.
However, if the Company can demonstrate that the
reason why this index was exceeded was a result of
cost increases caused by "State Initiated Cost
Changes", "Federally Initiated Cost Changes", or
"Regulatory Cost Reallocations", as defined in
Section 6 above, the Company may be entitled to
prove the continued existence of savings, as
provided in subsection (a) above.

(d) The implementation of these reopener provisions
is illustrated by the examples shown in Exhibit 5 to
this Settlement. (e) For purposes of subsections
(a), (b), and (c) above, the Company must meet the
same burden of evidentiary proof as occurs in a cost
of service rate case, subject to the usual review of
the Commission and permitted evidentiary challenges
by the Division and other intervenors.

9. NEW DEPRECIATION RATES AND TAX NORMALIZATION

Commencing on the Rate Consolidation Date, the Companies will
implement the new depreciation rates described in the Pre-Filed Testimony
of David M. Webster without the special distribution rate surcharge
proposed in the Companies' original filing in this Docket. In addition,
Narragansett will cease the flow through of tax deductions relating to the
cost of removal and the Companies will begin fully normalizing for all
book/tax timing differences.(81)

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81 For purposes of this Settlement, the Parties agree that current
accounting treatment of equity AFDC, ITC amortization, and ITC basis
adjustments shall remain unchanged and, as a result, not be
considered book/tax timing differences.

10. FUNDING OF DEFICIENCY IN RESERVE FOR DEFERRED TAXES

Narragansett has received from New England Power Company ("NEP") a
lump sum credit to its Contract Termination Charge ("CTC") account equal to
$17.5 million. The Parties agree that Narragansett shall apply such amount
(net of taxes payable on such monies) to reduce Narragansett's deficiency
in its reserve for deferred taxes. The Parties further agree that through
December 31, 2004, the first $5 million of certain CTC reconciliation
adjustments received by Narragansett from NEP pursuant to the Amendment to
Service Agreement contained in the NEP/Narragansett Wholesale Settlement in
FERC Docket 97-680-000 (the Wholesale Settlement) shall be retained by
Narragansett and applied (net of taxes payable on such monies) to further
reduce the deficiency. The source of such retained CTC reconciliation
adjustments will be limited to recoveries from third parties, pursuant to
section 1.2.2(g) of Appendix 1 to the Wholesale Settlement, and the
proceeds from future asset sales, referenced in section 1.1.4(d) of the
Wholesale Settlement. In Narragansett's first COS rate case filed to change
rates after the Rate Freeze Period, the Company will be permitted to
recover the remaining deficiency in such COS rate case by amortizing it
over a period such that the revenue requirement of the annual amortization
does not exceed $1 million, provided that the amortization shall not be
less than five years.

11. EARNINGS REPORTS

(A) RATE FREEZE PERIOD.

The Company will be required to file annual earnings reports with
the Commission by May 1 of each year during the Rate Freeze
Period. Copies also will be filed with all Parties. These reports
will be filed for informational purposes. The determination of
whether the Company has exceeded its allowed rate of return on
equity will be made at the end of the Rate Freeze Period.
Specifically, by May 1, 2005, Narragansett shall file an earnings
report with the Commission, calculating the five year average
return on equity on intrastate earnings for the period commencing
January 1, 2000 through December 31, 2004. For purposes of
calculating return and income taxes, Narragansett shall use the
imputed capital structure and associated costs of capital set
forth in subsection 7(B) above; provided, however, if
Narragansett's actual average common equity ratio falls below 50%
for any of the five years during the Rate Freeze Period, any party
may contend that the use of the average actual capital structure
for the five year period is more reasonable than the use of the
imputed actual capital structure.(82) For purposes of this five
year average earnings report, the allowed return on equity shall
be 10.5%. For purposes of these earnings reports, results will be
adjusted to reflect established Commission ratemaking principles.
However, there will be no adjustments to actual results to
recognize or annualize known and measurable changes. The return on
common equity will be calculated by dividing the net income
available for common equity by the common equity applicable to
rate base. The common equity applicable to rate base shall be
calculated by multiplying the common equity ratio required by this
subsection by rate base. Any accumulated earnings up to and
including 150 basis points over such allowed return on equity may
be retained by the Company. Any earnings from 150 to 250 basis
points shall be shared 50% with customers and 50% for the Company.
Any earnings over 250 basis points shall be shared 75% with
customers and 25% for Narragansett. The customers' share will be
credited to customers through the procedure described in
subsection (C) below. During the Rate Freeze Period, earnings
reported will not include an allowance for shared savings.

- ----------

82 The Company will use a five quarter average for determining rate base
and equity in the earnings calculation for earnings reports during
and after the Rate Freeze Period.

(B) POST-RATE FREEZE.

After the Rate Freeze Period, Narragansett will file
annual earnings reports for each year (commencing with the year
2005) showing the Company's return on equity on intrastate
earnings.(83) Copies will be filed with all Parties. Such filings
shall be made no later than May 1 of the succeeding year.
Narragansett shall be allowed to include its share of merger
savings allowed pursuant to the terms of Section 8 above in the
calculation of earnings. For purposes of these earnings reports,
results will be adjusted to reflect established Commission
ratemaking principles. However, there will be no adjustments to
actual results to recognize or annualize known and measurable
changes. Until the completion of Narragansett's first COS rate
case, the Company will use the imputed capital structure and cost
rates set forth in subsection 7(B) above; provided, however, that
if the actual equity ratio is less than 50% during the period
under review, any party may contend that the use of the average
actual capital structure is more reasonable than the use of the
imputed capital structure. After the first COS rate case, the
Company shall use the capital structure and cost rates approved by
the Commission in such case. The return on common equity will be
calculated by dividing the net income available for common equity
by the common equity applicable to rate base. The common equity
applicable to rate base shall be calculated by multiplying the
common equity ratio required by this subsection by rate base. Any
accumulated earnings over the Company's allowed rate of return, up
to and including 100 basis points, shall be shared 50% with
customers and 50% for the Company. Any earnings over 100 basis
points shall be shared 75% with customers and 25% for the Company.
The customers' share will be credited to customers in accordance
with the procedure identified in subsection (C) below.

- -----------

83 The earnings report requirements set forth in this Settlement
are in addition to any other earnings report requirements that may
be required by the Commission.

Prior to proposing a method of crediting customers for
the customers' share of earnings above the earnings thresholds,
the Companies will consult with the Parties to propose a mutually
acceptable method. Any credits to customers pursuant to this
subsection will be filed with the Commission for Commission review
and approval.

12. ENVIRONMENTAL RESPONSE FUND

An Environmental Response Fund shall be established to create a
mechanism to fund the recovery of "Environmental Response Costs", as
defined below.

(A) Definition of "Environmental Response Costs".
"Environmental Response Costs" are all the reasonable and
prudently incurred costs associated with remedial and
clean-up obligations of Narragansett, BVE, and Newport
arising out of the Companies' or their predecessors'
utility-related ownership and/or operation of
manufactured gas plants and sites associated with the
operation and disposal activities from such gas plants. A
list of the locations is provided in Exhibit 9 to this
Settlement. In addition to actual remedial and clean up
costs, "Environmental Response Costs" also include costs
of acquiring property associated with the clean up of
such sites as well as litigation costs, claims,
judgments, and settlements associated with such sites.
The Company will use best efforts to satisfy its
obligation to minimize the Environmental Response Costs
charged to the fund consistent with applicable regulatory
requirements and sound environmental policies and to
minimize litigation costs that may arise. Any applicable
insurance proceeds shall be credited to the fund. To the
extent the Company incurs any other extraordinary
environmental liability of which it is not aware as of
the date of this Settlement, the Company has the right to
request the Commission to allow such costs incurred in
connection with such extraordinary events to be included
as "Environmental Response Costs".

(B) Funding. Interest shall accrue, for the benefit of
customers, on any credit balances in the fund at the
customer deposit rate. No interest shall accrue on debit
balances. Any cash expenditures shall be charged to the
fund as long as the costs that are or have been incurred
are Environmental Response Costs, as defined above. The
fund shall be credited at the annual amount of $878,000
(the current amount reflected in rates for amortization
of such costs)or $73,167 per month.

(C) Annual Reports. Narragansett will file an annual report
with the Commission (and serve the Parties with copies)
providing a summary and accounting of all costs incurred
during such year which have been applied to the fund.
Each of the Parties reserve their rights to review and
challenge any costs that they believe do not fall within
the definition of "Environmental Response Costs", as
defined in subparagraph (A) above.

(D) Reservation of Rights. In the Company's first COS rate
case to establish rates after the Rate Freeze Period, all
Parties to this Settlement reserve their rights to take
any position they deem appropriate regarding (i) the
level of funding to be permitted in rates on a
prospective basis to recover costs charged to the fund as
of the date of such case, and/or (ii) whether the fund
should continue as designed in this Settlement for the
recovery of prospective costs.

13. STORM CONTINGENCY FUND

The Parties agree that Narragansett's Storm Contingency Fund, as
consolidated, shall have an annual funding level of $1,041,000 (subject to
Section 17); a threshold of $580,000 (which escalates each year in
accordance with Commission rules); and a deductible of $375,000.

14. TRANSMISSION RATES

On the Rate Consolidation Date, base transmission rates will be
consolidated, making all customers subject to the same set of transmission
rates, as reflected in Exhibit 2. However, in order to avoid an increase in
transmission rates for BVE and Newport customers in 2000, a separate
transmission adjustment factor shall be calculated for customers in the
Newport, BVE, and Narragansett service territories ("Zones"), to continue
the present allocation of transmission costs currently assigned to each
company. Beginning in the year 2001, Narragansett will eliminate the zonal
adjustment factors and apply one transmission adjustment factor for all
customers to recover the consolidated transmission costs incurred in excess
of revenue collected in the consolidated base transmission rates.

15. TRANSITION CHARGES

Beginning on the Rate Consolidation Date, there shall be "zonal"
transition charges. One zone will consist of customers in the current
Narragansett Electric service territory ("Narragansett Zone"). The second
zone shall consist of customers in the current BVE service territory
("Blackstone Zone"). The third zone shall consist of customers in the
current Newport service territory ("Newport Zone"). The transition charges
for the Narragansett Zone will be fixed in accordance with the following
schedule during the Rate Freeze Period:

Year Fixed Transition Charge
Narragansett Zone (cents per kWh)

2000 1.15
2001 1.05
2002 1.05
2003 1.00
2004 0.95

The transition charges in the Blackstone and Newport Zones will be
determined by calculating the balance of the Company's total Contract
Termination Charge expenses during the Rate Freeze Period less the
estimated transition charge revenues collected in the Narragansett Zone and
dividing the balance by the estimated kilowatt-hour deliveries in the
Blackstone and Newport Zones. The resulting transition charges in the
Blackstone and Newport Zones shall not exceed the amounts established for
the period through 2004 as of the date of this Settlement under
FERC-approved CTC rates for Blackstone and Newport, respectively
("Transition Charge Maximums"). Once transition charges converge in the
three zones, they will be set at the same rates, with applicable
adjustments being spread equally among the three zones.

All Parties reserve their rights to propose different rate designs
for transition charges after the Rate Freeze Period. During the Rate Freeze
Period, to the extent that Contract Termination Charge expenses are less
than the total transition charge revenue collected from customers in any
given year, any such overrecoveries (less amounts applied in accordance
with Section 10 above) shall be credited to customers, with interest at the
customer deposit rate, in the Blackstone and Newport Zones to lower
transition charges for the following year. Underrecoveries in any given
year may be collected, with interest at the customer deposit rate, in the
following year to the extent allowed under the Transition Charge Maximums
specified above. To the extent that any Contract Termination Charge
expenses are not collected during this period as a result of the Transition
Charge Maximums in the Blackstone and Newport Zones, any underrecoveries
will be deferred with interest at the customer deposit rate, for recovery
after the Rate Freeze Period through a methodology approved by the
Commission.

16. CONSOLIDATION OF BALANCES IN ADJUSTMENT PROVISIONS

The rates and tariffs of Narragansett include the adjustment
provisions (attached as Exhibit 6 and listed below), which shall apply to
all customers:

(i) Standard Offer Adjustment Provision
(ii) Transmission Service Cost Adjustment Provision
(iii) Non-Bypassable Transition Charge Adjustment Provision
(iv) Conservation and Load Management Adjustment Provision

Any balances (positive or negative) outstanding in any BVE or Newport
adjustment provisions shall be consolidated into the appropriate
Narragansett adjustment provision listed above.

17. ATTACHMENT FEE REVENUE

All revenue received from attachment and other telecommunication
company fees for use of distribution plant up to an annual amount of
$850,000 and 50% of all incremental revenue from such fees over $850,000,
will be included as above-the-line revenues in earnings reports and in all
future COS rate cases, including such revenues from any telecommunications
affiliates of the Company. The remaining 50% of all such incremental
revenue over the annual amount of $850,000 will be directly credited to the
Companies' Storm Fund account on an annual basis.

18. SALES OF PROPERTIES

(A) Annual Report on Sales. By March 1 of each year during and
after the Rate Freeze Period, the Company shall file an annual report with
the Commission listing any properties that have been sold in the prior
calendar year and indicating whether the property is classified as utility
property or non-utility property and the total proceeds received. All
Parties reserve their rights to make a claim to the Commission that all or
a portion of any of the proceeds from specified sales should be credited to
customers. The Company reserves its right to dispute any such claims.

(B) Notification to Attorney General and Division. Prior to
marketing for sale any utility or non-utility real estate property owned by
the Companies with a net book value of $250,000 or more, the Company shall
file a confidential notification with the Division and the Attorney
General, identifying the property that the Company is contemplating
selling. Unless the Division and the Attorney General otherwise agree, the
Company will not enter into a legally binding commitment to sell such
property until thirty days after providing the notification.

19. SERVICE QUALITY STANDARDS

The Parties agree that the Service Quality Performance Standards
set forth in Exhibit 7 shall apply through the Rate Freeze Period.
Thereafter, the standards shall remain in effect, but may be modified by
order issued by the Commission. The Parties reserve their rights to propose
modifications to the Commission at any time after the Rate Freeze Period or
in the Company's first rate case, including any rate case filed by the
Company that seeks to change rates on and after January 1, 2005. If at any
time while the Service Quality Performance Standards are in effect, the
Commission finds that there is a significant and persistent deterioration
in service quality (after a hearing in which the Company has been provided
the right to appear and present evidence), the penalties provided in the
standards shall be doubled and the Company shall be required to file a
remedial plan. If after one year from such finding, the Commission finds
that the Company has not carried out its remedial plan and, as a result,
the significant and persistent problems with service quality have not been
remediated, the Commission may suspend the right of the Company to retain a
share of merger savings on a prospective basis until the Company
demonstrates in a hearing before the Commission that service quality has
returned at least to the levels that existed prior to the merger.

20. EXPANSION OF LOW INCOME PROGRAM TO INCLUDE LIHEAP CUSTOMERS

The Parties agree that Narragansett's Low Income Rate A-60 shall
be expanded to include all customers who are eligible for assistance
through the state's LIHEAP program. The first $600,000 of incremental cost
of such expansion shall be borne by the Company during the Rate Freeze
Period (subject to increases under the provisions of Section 4(d) above).
The balance shall be tracked annually by the Company and recovered from all
customers of the Company through a fully reconciling uniform per kWh
adjustment factor. After the Rate Freeze Period, the entire incremental
cost shall be tracked and recovered from customers through the reconciling
adjustment factor until the Company's first rate case. In the Company's
first rate case that establishes new rates after the Rate Freeze Period,
the full incremental cost shall be rolled into distribution rates for
recovery from all customers.

21. NO COST RECOVERY OF "GOLDEN PARACHUTES"

The Companies agree that it shall not recover any costs from
customers associated with the so-called "golden parachute" payments to any
of the EUA or NEES parent company officers that are triggered as a result
of the merger of NEES and EUA or NEES and National Grid. Nor shall the
Company include in rates the costs of any "golden parachute" payments for
such parent company officers arising from other future mergers.

22. EXPIRATION OF SETTLEMENT

If the closing of the merger between New England Electric System
and Eastern Utilities Associates does not occur, this Settlement agreement
will terminate and have no legal effect. In such case, the cost of service
and earnings of the Companies will be subject to normal course of review as
if this Settlement had never been approved. If the merger does not occur
the Parties and the Commission are not precluded from reviewing earnings of
the Companies for 1999 and 2000 to determine whether there were any
overearnings that should be credited to customers.

23. FULLY ALLOCATED COST OF SERVICE AND RATE DESIGN FILING IN 2004

In Docket 2710, the Commission approved a settlement in which
Narragansett agreed to make a revenue neutral filing with the Commission
for the purpose of redesigning the Company's rates for the G-32, B-32,
G-62, and B-62 classes. The Parties agree that the Company is no longer
obligated to make such filing. Instead, if the Company has not filed a cost
of service rate case to change rates for usage on and after January 1,
2005, the Company shall make a revenue neutral filing of a fully allocated
cost of service study by June 1, 2004 and propose new rates for all classes
to take effect for usage on and after January 1, 2005. The fully allocated
cost of service study will be subject to the review of the Commission and
permitted evidentiary challenges by the Division and other parties. If and
when the Company files its first cost of service rate case to change rates
on or after January 1, 2005, the Company will include a fully allocated
cost of service study in such filing.

24. OTHER PROVISIONS

(A) The Parties agree not to oppose the request of the Companies to
obtain EWG status for EUA's ownership share of Ocean State Power I and II.

(B) This Settlement resolves all issues in the EUA 1999
overearnings Docket 2911 and such docket shall be considered closed as a
result of approval of this Settlement and no other claims regarding
overearnings in 1999 shall be made against the Companies.

(C) If at any time during the term of this Settlement the Company
becomes aware of a proceeding at the Securities and Exchange Commission or
FERC that will change the allocations of costs among Narragansett Electric
and its affiliates, the Company will notify the Attorney General and the
Division in writing or provide a copy of the notice to such proceedings.

(D) Unless expressly stated herein, the making of this Settlement
establishes no principles and shall not be deemed to foreclose any Party
from making any contention in any other proceeding or investigation other
than Division Docket D-99-12.

(E) This Settlement is the product of settlement negotiations. The
content of those negotiations is privileged and all offers of settlement
shall be without prejudice to the position of any Party.

(F) This Settlement is submitted on the condition that it be
approved in full by the Commission, and on the further condition that if
the Commission does not approve the Settlement in its entirety, the
Settlement shall be deemed withdrawn and shall not constitute a part of the
record in any proceeding or used for any purpose.

(G) The Parties recognize that the Commission has an ongoing
obligation to modify rates to protect the public against improper and
unreasonable rates that cannot be precluded by a settlement agreement.

Respectfully submitted,

The Narragansett Electric Company
By its Attorney

---------------------------
Ronald T. Gerwatowski
General Counsel

Blackstone Valley Electric Company
and Newport Electric Corporation
By their Attorney

----------------------------
David A. Fazzone of
David A. Fazzone, P.C. and
McDermott, Will & Emery

The Division of Public Utilities and Carriers
By its Attorney

---------------------------
Elizabeth A. Kelleher
Special Assistant Attorney General

The Department of the Attorney General
By its Attorney

---------------------------
Paul Roberti
Assistant Attorney General

The Energy Council of Rhode Island
By its Attorney

---------------------------
Andrew J. Newman
Rubin and Rudmin LLP

The National Grid Group, plc
By its Attorneys,

------------------------
Paul K. Connolly, Jr.
Patricia M. French
LeBoeuf, Lamb, Greene & MacRae,
LLP

EXHIBITS

Exhibit 1 Summary of Hold Harmless Rate Design Mechanisms
Exhibit 2 Cover Sheets for All Rates
Exhibit 3 Rates G-22, N-01, and Amended A-32 & A-60
Exhibit 4 Illustrations of Savings Proof
4a: Savings Proof in 2002 or 2003
4b: Second Savings Proof in Rate Case
4c: Second Savings Proof in 2007 (without rate case)
Exhibit 5 Illustrations of Reopener Provisions and Thresholds
Exhibit 6 Adjustment Provisions
Exhibit 7 Service Quality Performance Standards
Exhibit 8 Terms and Conditions
Exhibit 9 List of Manufactured Gas Plant Locations

File: ERR Narragansett Electric
Range: ERR BVE/Newport Electric
R.I.P.U.C. Docket No. 2930
Exhibit 1
Page 1 of 2
THE NARRAGANSETT ELECTRIC COMPANY
ANNUAL HOLD HARMLESS SUMMARY

Hold Harmless Measures Beginning on the Rate Consolidation Date

Blackstone

<S> <C> <C> <C>
R-1/W-1 Switched Rate Mapping to Rate A-18 from Rate A-16 $48,924
R-2 Rate Design Change $(1,203)
R-3 Switched Rate Mapping to Rate A-32 from Rate A-16 $101,873
G-1 Customer Charge Credit $96,974
G-2 Grandfathered Rate with Continued Discount $(119,265)
Many Classes Hold Harmless Credits (See Exhibit JMM-16) $206,424
--------

Newport

R-1/W-1 Switched Rate Mapping to Rate A-18 from Rate A-16 $247,773
R-2 Rate Design Change $(12,097)
G-1 Customer Charge Credit $15,752
G-2 Switched Rate Mapping to New Rate G-22 $(162,861)
Many Classes Hold Harmless Credits (See Exhibit JMM-16) $3,661
------
$92,228
-------
Total Hold Harmless Measures $425,955

Hold Harmless Credits Expiring on January 1, 2005

Blackstone

G-1 Customer Charge Credit $96,974
Many Classes Hold Harmless Credits (See Exhibit JMM-16) $206,424
--------

Newport

G-1 Customer Charge Credit $15,752
Many Classes Hold Harmless Credits (See Exhibit JMM-16) $3,661
------
$19,413
-------
Total Hold Harmless Credits Expiring January 1, 2005 $322,811

</TABLE>

THE NARRAGANSETT ELECTRIC COMPANY
CALCULATION OF HOLD HARMLESS CREDITS

Step One - After the approval of Rate Plan

Determine eligible Blackstone/Newport customers using 1999 billing
determinants

If New Rates times 1999 Billing determinants less Old Rates times 1999
Billing determinants > zero Then Customer is eligible to receive annual
credit

Step Two - January each year from 2001 to 2005

Determine Benchmark Distribution, Transmission and Transition Rates
each year

Benchmark Distribution Rate = Distribution Rate prior to Consolidation
Benchmark Transmission Rate = Transmission Rate prior to Consolidation
plus Prior Year increase in the Consolidated Transmission Rate Benchmark
Transition Rate = Actual CTC billed relating to appropriate zone

Step Three - January each year from 2001 to 2005

Determine Credits for prior year

If Actual prior years Bills less Benchmark Rates times prior years
Billing determinants > zero Then Customer receives a credit to their
next bill

Other Rules

If a customer moves from its current zone during the year the
customer is removed from the eligibility list
If a customer has a negative credit the customer is removed from the
eligibility list
No customer receives credits for bills after January 1, 2005

EXHIBIT 2

THE NARRAGANSETT ELECTRIC COMPANY Effective
BASIC RESIDENTIAL RATE (A-16) April 1, 2000
Retail Delivery Service

R.I.P.U.C. No. 1100-A
<TABLE>

Monthly Charge As Adjusted

Rates for Retail Delivery Service

<S> <C>
Customer Charge per month $2.54

Non-Bypassable Transition Charge per kWh 1.150(cent)

Transmission Charge per kWh 0.436(cent)

Transmission Adjustment Factor per kWh 0.068(cent)

Distribution Charge per kWh* 3.642(cent)

Minimum Charge per month $2.54

Conservation and Load Management Adjustment per kWh 0.230(cent)(Eff. Jan. 1, 1997)

Additional Delivery Rates for Blackstone Valley Zone

Zonal Transition Factor per kWh 0.890(cent)

Transmission Adjustment Credit per kWh 0.042(cent)

Additional Delivery Rates for Newport Zone

Zonal Transition Factor per kWh 0.910(cent)

Transmission Adjustment Credit per kWh 0.064(cent)

Rates for Standard Offer Service or Last Resort Service (Optional)

Standard Offer per kWh 3.800(cent)(Eff. January 1, 2000)

Last Resort per kWh per Last Resort Service tariff

* Includes 0.068(cent)per kWh for phase-in of FAS 106 (Eff. Jan. 1, 1998), (0.038(cent)) per kWh for Rate Settlement
credit, 0.000(cent)per kWh for Standard Offer Adjustment Provision (Eff. Jan. 1, 2000) and 0.214(cent)per kWh and
0.152(cent)per kWh for Performance Based Rate Adjustments effective Jan. 1, 1997 and Jan. 1, 1998,
respectively.

TAX NOTE: THE RATES LISTED ABOVE DO NOT REFLECT GROSS EARNINGS TAX OR SALES TAXES. HOWEVER, SUCH TAXES,
WHEN APPLICABLE, WILL APPEAR ON BILLS SENT TO CUSTOMERS.

Other Rate Clauses apply as usual.

</TABLE>

THE NARRAGANSETT ELECTRIC COMPANY Effective
RESIDENTIAL WATER HEATER CONTROL RATE (A-18) April 1, 2000
Retail Delivery Service

R.I.P.U.C. No. 1101-A

Monthly Charge As Adjusted

Rates for Retail Delivery Service

<S> <C>
Customer Charge per month $2.52

Non-Bypassable Transition Charge per kWh 1.150(cent)

Transmission Charge per kWh 0.387(cent)

Transmission Adjustment Factor per kWh 0.068(cent)

Distribution Charge per kWh* 3.536(cent)

Credit per kWh for the first 750 kWh per month 0.661(cent)

Minimum Charge per month $2.52

Conservation and Load Management Adjustment per kWh 0.230(cent)(Eff. Jan. 1, 1997)

Additional Delivery Rates for Blackstone Valley Zone

Zonal Transition Factor per kWh 0.890(cent)

Transmission Adjustment Credit per kWh 0.042(cent)

Additional Delivery Rates for Newport Zone

Zonal Transition Factor per kWh 0.910(cent)

Transmission Adjustment Credit per kWh 0.064(cent)

Rates for Standard Offer Service or Last Resort Service (Optional)

Standard Offer per kWh 3.800(cent)(Eff. January 1, 2000)

Last Resort per kWh per Last Resort Service tariff

TAX NOTE: THE RATES LISTED ABOVE DO NOT REFLECT GROSS EARNINGS TAX OR SALES TAXES. HOWEVER, SUCH TAXES,
WHEN APPLICABLE, WILL APPEAR ON BILLS SENT TO CUSTOMERS.

Other Rate Clauses apply as usual.

</TABLE>

THE NARRAGANSETT ELECTRIC COMPANY Effective
RESIDENTIAL TIME-OF-USE RATE (A-32) April 1, 2000
Retail Delivery Service

R.I.P.U.C. No. 1102-A

Monthly Charge As Adjusted

Rates for Retail Delivery Service

<S> <C>
Customer Charge per month $2.30

Time-of-use Metering Charge per month $4.44

Non-Bypassable Transition Charge per kWh 1.150(cent)

Transmission Charge per kWh 0.392(cent)

Transmission Adjustment Factor per kWh 0.068(cent)

Distribution Charge per kWh* 2.558(cent)

Conservation and Load Management Adjustment per kWh 0.230(cent)(Eff. Jan. 1, 1997)

Additional Delivery Rates for Blackstone Valley Zone

Zonal Transition Factor per kWh 0.890(cent)

Transmission Adjustment Credit per kWh 0.042(cent)

Additional Delivery Rates for Newport Zone

Zonal Transition Factor per kWh 0.910(cent)

Transmission Adjustment Credit per kWh 0.064(cent)

Rates for Standard Offer Service or Last Resort Service (Optional)

Standard Offer per kWh 3.800(cent)(Eff. January 1, 2000)

Last Resort per kWh per Last Resort Service tariff

TAX NOTE: THE RATES LISTED ABOVE DO NOT REFLECT GROSS EARNINGS TAX OR SALES TAXES. HOWEVER, SUCH TAXES,
WHEN APPLICABLE, WILL APPEAR ON BILLS SENT TO CUSTOMERS.

Other Rate Clauses apply as usual.

</TABLE>

THE NARRAGANSETT ELECTRIC COMPANY Effective
LOW INCOME RATE (A-60) April 1, 2000
Retail Delivery Service

R.I.P.U.C. No. 1103-A
Monthly Charge As Adjusted

Rates for Retail Delivery Service

<S> <C>
Non-Bypassable Transition Charge per kWh 1.150(cent)

Transmission Charge per kWh 0.338(cent)

Transmission Adjustment Factor per kWh 0.068(cent)

Distribution Charge per kWh* 2.551(cent)

Water Heater Credit per kWh for the first 750 kWh per month 0.661(cent)

Conservation and Load Management Adjustment per kWh 0.230(cent)(Eff. Jan. 1, 1997)

A-60 Rate Credit 0.227(cent)

Additional Delivery Rates for Blackstone Valley Zone

Zonal Transition Factor per kWh 0.890(cent)

Transmission Adjustment Credit per kWh 0.042(cent)

Blackstone Distribution Charge per first 300 kWh (1.436)(cent)

Blackstone Distribution Charge in excess 300 kWh 1.194(cent)

Additional Delivery Rates for Newport Zone

Zonal Transition Factor per kWh 0.910(cent)

Transmission Adjustment Credit per kWh 0.064(cent)

Newport Distribution Charge first 300 kWh (0.782)(cent)

Newport Distribution Charge in excess 300 kWh 1.952(cent)

Rates for Standard Offer Service or Last Resort Service (Optional)

Standard Offer per kWh 3.800(cent)(Eff. January 1, 2000)

Last Resort per kWh per Last Resort Service tariff

* Includes 0.068(cent)per kWh for phase-in of FAS 106 (Eff. Jan. 1, 1998), (0.038(cent)) per kWh for Rate Settlement
credit, and 0.000(cent)per kWh for Standard Offer Adjustment Provision (Eff. Jan. 1, 2000).

TAX NOTE: THE RATES LISTED ABOVE DO NOT REFLECT GROSS EARNINGS TAX OR SALES TAXES. HOWEVER, SUCH TAXES,
WHEN APPLICABLE, WILL APPEAR ON BILLS SENT TO CUSTOMERS.

Other Rate Clauses apply as usual.
</TABLE>

THE NARRAGANSETT ELECTRIC COMPANY Effective
GENERAL C&I BACK-UP SERVICE RATE (B-02) April 1, 2000
Retail Delivery Service

R.I.P.U.C. No. 1117-A

Monthly Charge As Adjusted
Rates for Rates for
Back-Up Service Supplemental Service

Rates for Retail Delivery Service

<S> <C> <C>
Customer Charge per month $103.41 n/a

Distribution Demand Charge per kW in excess 10 kW $2.91 $2.91

Transmission Demand Charge per kW in excess 10 kW $1.40 $1.40

Transmission Adjustment Factor per kWh 0.068(cent) 0.068(cent)

Distribution Energy Charge per kWh * 0.992(cent) 0.992(cent)

Non-bypassable Transition Charge per kWh n/a 1.150(cent)

C&LM Adjustment per kWh n/a 0.230(cent)

Additional Delivery Rates for Blackstone Valley Zone

Zonal Transition Factor per kWh n/a 0.890(cent)

Transmission Adjustment Credit per kWh 0.042(cent) 0.042(cent)

Additional Delivery Rates for Newport Zone

Zonal Transition Factor per kWh n/a 0.910(cent)

Transmission Adjustment Credit per kWh 0.064(cent) 0.064(cent)

Rates for Standard Offer Service or Last Resort Service (Optional)

Standard Offer per kWh n/a 3.800(cent)

Last Resort per kWh n/a per Last Resort Service tariff

* Includes 0.068(cent)per kWh for phase-in of FAS 106 (Eff. Jan. 1, 1998), (0.038(cent)) per kWh for Rate Settlement
credit, 0.000(cent)per kWh for Standard Offer Adjustment Provision (Eff. Jan. 1, 2000) and 0.214(cent)per kWh and
0.152(cent)per kWh for Performance Based Rate Adjustment effective Jan. 1, 1997 and Jan. 1, 1998 respectively.

TAX NOTE: THE RATES LISTED ABOVE DO NOT REFLECT GROSS EARNINGS TAX OR SALES TAXES. HOWEVER, SUCH TAXES, WHEN
APPLICABLE, WILL APPEAR ON BILLS SENT TO CUSTOMERS.

Other Rate Clauses apply as usual.

</TABLE>

THE NARRAGANSETT ELECTRIC COMPANY Effective
SMALL C&I BACK-UP SERVICE RATE (B-06) April 1, 2000
Retail Delivery Service

R.I.P.U.C. No. 1118-A

Monthly Charge As Adjusted
Rates for Rates for
Back-Up Service Supplemental Service

Rates for Retail Delivery Service

<S> <C> <C>
Customer Charge per month $5.73 n/a

Transmission Energy Charge per kWh 0.536(cent) 0.536(cent)

Transmission Adjustment Factor per kWh 0.068(cent) 0.068(cent)

Distribution Energy Charge per kWh * 3.860(cent) 3.860(cent)

Non-bypassable Transition Charge per kWh n/a 1.150(cent)

C&LM Adjustment per kWh n/a 0.230(cent)

Additional Delivery Rates for Blackstone Valley Zone

Zonal Transition Factor per kWh n/a 0.890(cent)

Transmission Adjustment Credit per kWh 0.042(cent) 0.042(cent)

Additional Delivery Rates for Newport Zone

Zonal Transition Factor per kWh n/a 0.910(cent)

Transmission Adjustment Credit per kWh 0.064(cent) 0.064(cent)

Rates for Standard Offer Service or Last Resort Service (Optional)

Standard Offer per kWh n/a 3.800(cent)

Last Resort per kWh n/a per Last Resort Service tariff

* Includes 0.068(cent)per kWh for phase-in of FAS 106 (Eff. Jan. 1, 1998), (0.038(cent)) per kWh for Rate Settlement
credit, 0.000(cent)per kWh for Standard Offer Adjustment Provision (Eff. Jan. 1, 2000) and 0.214(cent)per kWh and
0.152(cent)per kWh for Performance Based Rate Adjustment effective Jan. 1, 1997 and Jan. 1, 1998 respectively.

TAX NOTE: THE RATES LISTED ABOVE DO NOT REFLECT GROSS EARNINGS TAX OR SALES TAXES. HOWEVER, SUCH TAXES, WHEN
APPLICABLE, WILL APPEAR ON BILLS SENT TO CUSTOMERS.

Other Rate Clauses apply as usual.
</TABLE>

THE NARRAGANSETT ELECTRIC COMPANY Effective
200 KW BACK-UP SERVICE RATE (B-32) April 1, 2000
Retail Delivery Service

R.I.P.U.C. No. 1119-A
Monthly Charge As Adjusted
Rates for Rates for
Back-Up Service Supplemental Service
Rates for Retail Delivery Service

<S> <C> <C>
Customer Charge per month $236.43 n/a

Transmission Demand Charge per kW $1.27 $1.27

Distribution Demand Charge per kW $1.56 $1.56

Transmission Adjustment Factor per kWh 0.068(cent) 0.068(cent)

Distribution Energy Charge per kWh * 1.101(cent) 1.101(cent)

Non-bypassable Transition Charge per kWh n/a 1.150(cent)

C&LM Adjustment per kWh n/a 0.230(cent)

Additional Delivery Rates for Blackstone Valley Zone

Zonal Transition Factor per kWh n/a 0.890(cent)

Transmission Adjustment Credit per kWh 0.042(cent) 0.042(cent)

Additional Delivery Rates for Newport Zone

Zonal Transition Factor per kWh n/a 0.910(cent)

Transmission Adjustment Credit per kWh 0.064(cent) 0.064(cent)

Rates for Standard Offer Service or Last Resort Service (Optional)

Standard Offer per kWh n/a 3.800(cent)

Last Resort per kWh n/a per Last Resort Service tariff

* Includes 0.068(cent)per kWh for phase-in of FAS 106 (Eff. Jan. 1, 1998), (0.038(cent)) per kWh for Rate Settlement
credit, 0.000(cent)per kWh for Standard Offer Adjustment Provision (Eff. Jan. 1, 2000) and 0.214(cent)per kWh and
0.152(cent)per kWh for Performance Based Rate Adjustment effective Jan. 1, 1997 and Jan. 1, 1998 respectively.

TAX NOTE: THE RATES LISTED ABOVE DO NOT REFLECT GROSS EARNINGS TAX OR SALES TAXES. HOWEVER, SUCH TAXES, WHEN
APPLICABLE, WILL APPEAR ON BILLS SENT TO CUSTOMERS.

Other Rate Clauses apply as usual.

</TABLE>

THE NARRAGANSETT ELECTRIC COMPANY Effective
3,000 KW BACK-UP SERVICE RATE (B-62) April 1, 2000
Retail Delivery Service

R.I.P.U.C. No. 1120-A

Monthly Charge As Adjusted
Rates for Rates for
Back-Up Service Supplemental Service
Rates for Retail Delivery Service

<S> <C> <C>
Customer Charge per month $17,118.72 n/a

Distribution Demand Charge per kW $0.75 $0.75

Transmission Demand Charge per kW $1.39 $1.39

Transmission Adjustment Factor per kWh 0.068(cent) 0.068(cent)

Distribution Energy Charge per kWh * 0.396(cent) 0.396(cent)

Non-bypassable Transition Charge per kWh n/a 1.150(cent)

C&LM Adjustment per kWh n/a 0.230(cent)

Additional Delivery Rates for Blackstone Valley Zone

Zonal Transition Factor per kWh n/a 0.890(cent)

Transmission Adjustment Credit per kWh 0.042(cent) 0.042(cent)

Additional Delivery Rates for Newport Zone

Zonal Transition Factor per kWh n/a 0.910(cent)

Transmission Adjustment Credit per kWh 0.064(cent) 0.064(cent)

Rates for Standard Offer Service or Last Resort Service (Optional)

Standard Offer per kWh n/a 3.800(cent)

Last Resort per kWh n/a per Last Resort Service tariff

* Includes 0.068(cent)per kWh for phase-in of FAS 106 (Eff. Jan. 1, 1998), (0.038(cent)) per kWh for Rate Settlement
credit, 0.000(cent)per kWh for Standard Offer Adjustment Provision (Eff. Jan. 1, 2000) and 0.214(cent)per kWh and
0.152(cent)per kWh for Performance Based Rate Adjustment effective Jan. 1, 1997 and Jan. 1, 1998 respectively.

TAX NOTE: THE RATES LISTED ABOVE DO NOT REFLECT GROSS EARNINGS TAX OR SALES TAXES. HOWEVER, SUCH TAXES, WHEN
APPLICABLE, WILL APPEAR ON BILLS SENT TO CUSTOMERS.

Other Rate Clauses apply as usual.

</TABLE>

THE NARRAGANSETT ELECTRIC COMPANY
Effective
HIGH VOLTAGE BACK-UP SERVICE RATE (B-72) April 1, 2000
High Voltage Delivery Service

R.I.P.U.C. No. 1122

Monthly Charge As Adjusted
Rates for Rates for
Back-Up Service Supplemental Service
Rates for High Voltage Delivery Service

<S> <C> <C>
Customer Charge per month $63.75 n/a

Distribution Demand Charge per kW $ 0.35 $ 0.35

Transmission Demand Charge per kW $ 1.34 $ 1.34

Transmission Adjustment Factor per kWh 0.068(cent) 0.068(cent)

Distribution Energy Charge per kWh* 0.396(cent) 0.396(cent)

Non-Bypassable Transition Charge per kWh n/a 1.150(cent)

Conservation and Load Management Adjustment per kWh n/a 0.230(cent)

Additional Delivery Rates for Blackstone Valley Zone

Zonal Transition Factor per kWh n/a 0.890(cent)

Transmission Adjustment Credit per kWh 0.042(cent) 0.042(cent)

Additional Delivery Rates for Newport Zone

Zonal Transition Factor per kWh n/a 0.910(cent)

Transmission Adjustment Credit per kWh 0.064(cent) 0.064(cent)

Rates for Standard Offer Service or Last Resort Service (Optional)

Standard Offer per kWh n/a 3.800(cent)

Last Resort per kWh n/a per Last Resort Service tariff

* Includes 0.068(cent)per kWh for phase-in of FAS 106 (Eff. Jan. 1, 1998), (0.038(cent)) per kWh for Rate Settlement
credit, 0.000(cent)per kWh for Standard Offer Adjustment Provision (Eff. Jan. 1, 2000) and 0.214(cent)per kWh and
0.152(cent)per kWh for Performance Based Rate Adjustment effective Jan. 1, 1997 and Jan. 1, 1998
respectively.

TAX NOTE: THE RATES LISTED ABOVE DO NOT REFLECT GROSS EARNINGS TAX OR SALES TAXES (WHEN APPLICABLE).
HOWEVER, SUCH TAXES, WHEN APPLICABLE, WILL APPEAR ON BILLS SENT TO CUSTOMERS.

Other Rate Clauses apply as usual.
</TABLE>

THE NARRAGANSETT ELECTRIC COMPANY Effective
SMALL C&I RATE (C-06) April 1, 2000
Retail Delivery Service

R.I.P.U.C. No. 1104-A

Monthly Charge As Adjusted

Rates for Retail Delivery Service

<S> <C>
Customer Charge per month $5.73

Unmetered Charge per month $1.83

Non-Bypassable Transition Charge per kWh 1.150(cent)

Transmission Charge per kWh 0.536(cent)

Transmission Adjustment Factor per kWh 0.068(cent)

Distribution Charge per kWh* 3.860(cent)

Conservation and Load Management Adjustment per kWh 0.230(cent)(Eff. Jan 1, 1997)

Additional Delivery Rates for Blackstone Valley Zone

Zonal Transition Factor per kWh 0.890(cent)

Transmission Adjustment Credit per kWh 0.042(cent)

Customer Charge Credit equal to the Maximum of (698 - billed kWh) x $0.00338 or zero

Additional Delivery Rates for Newport Zone

Zonal Transition Factor per kWh 0.910(cent)

Transmission Adjustment Credit per kWh 0.064(cent)

Customer Charge Credit equal to the Maximum of (124 - billed kWh) x $0.01844 or zero

Rates for Standard Offer Service or Last Resort Service (Optional)

Standard Offer per kWh 3.800(cent)(Eff. January 1, 2000)

Last Resort per kWh per Last Resort Service tariff

TAX NOTE: THE RATES LISTED ABOVE DO NOT REFLECT GROSS EARNINGS TAX OR SALES TAXES. HOWEVER, SUCH TAXES, WHEN
APPLICABLE, WILL APPEAR ON BILLS SENT TO CUSTOMERS.

Other Rate Clauses apply as usual.

</TABLE>

THE NARRAGANSETT ELECTRIC COMPANY Effective
RESIDENTIAL STORAGE HEATING RATE (E-30) April 1, 2000
Retail Delivery Service

R.I.P.U.C. No. 1105-A

Monthly Charge As Adjusted

Rates for Retail Delivery Service

<S> <C>
Customer Charge per month $7.54

Non-Bypassable Transition Charge per kWh 1.150(cent)

Transmission Charge per kWh 0.261(cent)

Transmission Adjustment Factor per kWh 0.068(cent)

Distribution Charge per kWh* 1.582(cent)

Conservation and Load Management Adjustment per kWh 0.230(cent)(Eff. Jan. 1, 1997)

Rates for Standard Offer Service or Last Resort Service (Optional)

Standard Offer per kWh 3.800(cent)(Eff. January 1, 2000)

Last Resort per kWh per Last Resort Service tariff

TAX NOTE: THE RATES LISTED ABOVE DO NOT REFLECT GROSS EARNINGS TAX OR SALES TAXES. HOWEVER, SUCH TAXES, WHEN
APPLICABLE, WILL APPEAR ON BILLS SENT TO CUSTOMERS.

Other Rate Clauses apply as usual.
</TABLE>

THE NARRAGANSETT ELECTRIC COMPANY Effective
STORAGE COOLING RATE (E-40) April 1, 2000
Retail Delivery Service

R.I.P.U.C. No. 1106-A

Monthly Charge As Adjusted

Rates for Retail Delivery Service

<S> <C>
Customer Charge per month $75.15

Non-Bypassable Transition Charge per kWh 1.150(cent)

Transmission Charge per kWh 0.141(cent)

Transmission Adjustment Factor per kWh 0.068(cent)

Distribution Charge per kWh*
Peak/Shoulder 2.536(cent)
Off Peak 0.949(cent)

Conservation and Load Management Adjustment per kWh 0.230(cent)(Eff. Jan. 1, 1997)

Rates for Standard Offer Service or Last Resort Service (Optional)

Standard Offer per kWh 3.800(cent)(Eff. January 1, 2000)

Last Resort per kWh per Last Resort Service tariff

TAX NOTE: THE RATES LISTED ABOVE DO NOT REFLECT GROSS EARNINGS TAX OR SALES TAXES. HOWEVER, SUCH TAXES, WHEN
APPLICABLE, WILL APPEAR ON BILLS SENT TO CUSTOMERS.

Other Rate Clauses apply as usual.

</TABLE>

THE NARRAGANSETT ELECTRIC COMPANY Effective
GENERAL C&I RATE (G-02) April 1, 2000
Retail Delivery Service

R.I.P.U.C. No. 1107-A

Monthly Charge As Adjusted

Rates for Retail Delivery Service

<S> <C>
Customer Charge per month $103.41

Transmission Charge per kW in excess of 10 kW $1.40

Distribution Charge per kW in excess of 10 kW $2.91

Non-Bypassable Transition Charge per kWh 1.150(cent)

Transmission Adjustment Factor per kWh 0.068(cent)

Distribution Charge per kWh* 0.992(cent)

Conservation and Load Management Adjustment per kWh 0.230(cent)(Eff. Jan. 1, 1997)

Additional Delivery Rates for Blackstone Valley Zone

Zonal Transition Factor per kWh 0.890(cent)

Transmission Adjustment Credit per kWh 0.042(cent)

Additional Delivery Rates for Newport Zone

Zonal Transition Factor per kWh 0.910(cent)

Transmission Adjustment Credit per kWh 0.064(cent)

Rates for Standard Offer Service or Last Resort Service (Optional)

Standard Offer per kWh 3.800(cent)(Eff. January 1, 2000)

Last Resort per kWh per Last Resort Service tariff

TAX NOTE: THE RATES LISTED ABOVE DO NOT REFLECT GROSS EARNINGS TAX OR SALES TAXES. HOWEVER, SUCH TAXES, WHEN
APPLICABLE, WILL APPEAR ON BILLS SENT TO CUSTOMERS.

Other Rate Clauses apply as usual.
</TABLE>

THE NARRAGANSETT ELECTRIC COMPANY Effective
LIMITED MEDIUM SECONDARY VOLTAGE C&I RATE (G-22) April 1, 2000
Retail Delivery Service

R.I.P.U.C. No.

Monthly Charge As Adjusted

Rates for Retail Delivery Service

<S> <C>
Distribution Charge per kW $1.50

Non-Bypassable Transition Charge per kWh 1.150(cent)

Transmission Charge per kWh 0.386(cent)

Transmission Adjustment Factor per kWh 0.068(cent)

Distribution Charge per kWh* 2.215(cent)

Conservation and Load Management Adjustment per kWh 0.230(cent)(Eff. Jan. 1, 1997)

Additional Delivery Rates for Blackstone Valley Zone

Zonal Transition Factor per kWh 0.890(cent)

Transmission Adjustment Credit per kWh 0.042(cent)

Additional Delivery Rates for Newport Zone

Zonal Transition Factor per kWh 0.910(cent)

Transmission Adjustment Credit per kWh 0.064(cent)

Rates for Standard Offer Service or Last Resort Service (Optional)

Standard Offer per kWh 3.800(cent)(Eff. January 1, 2000)

Last Resort per kWh per Last Resort Service tariff

TAX NOTE: THE RATES LISTED ABOVE DO NOT REFLECT GROSS EARNINGS TAX OR SALES TAXES. HOWEVER, SUCH TAXES, WHEN
APPLICABLE, WILL APPEAR ON BILLS SENT TO CUSTOMERS.

Other Rate Clauses apply as usual.

</TABLE>

THE NARRAGANSETT ELECTRIC COMPANY Effective
200 KW DEMAND RATE (G-32) April 1, 2000
Retail Delivery Service

R.I.P.U.C. No. 1108-A

Monthly Charge As Adjusted

Rates for Retail Delivery Service

<S> <C>
Customer Charge per month $236.43

Transmission Charge per kW $1.27

Distribution Charge per kW $1.56

Non-Bypassable Transition Charge per kWh 1.150(cent)

Transmission Adjustment Factor per kWh 0.068(cent)

Distribution Charge per kWh* 1.101(cent)

Conservation and Load Management Adjustment per kWh 0.230(cent)(Eff. Jan. 1, 1997)

Additional Delivery Rates for Blackstone Valley Zone

Zonal Transition Factor per kWh 0.890(cent)

Transmission Adjustment Credit per kWh 0.042(cent)

Additional Delivery Rates for Newport Zone

Zonal Transition Factor per kWh 0.910(cent)

Transmission Adjustment Credit per kWh 0.064(cent)

Rates for Standard Offer Service or Last Resort Service (Optional)

Standard Offer per Wh 3.800(cent)(Eff. January 1, 2000)

Last Resort per kWh per Last Resort Service tariff

TAX NOTE: THE RATES LISTED ABOVE DO NOT REFLECT GROSS EARNINGS TAX OR SALES TAXES (WHEN APPLICABLE). HOWEVER,
SUCH TAXES, WHEN APPLICABLE, WILL APPEAR ON BILLS SENT TO CUSTOMERS.

Other Rate Clauses apply as usual.
</TABLE>

THE NARRAGANSETT ELECTRIC COMPANY Effective
3000 KW DEMAND RATE (G-62) April 1, 2000
Retail Delivery Service

R.I.P.U.C. No. 1109-A

Monthly Charge As Adjusted

Rates for Retail Delivery Services

<S> <C>
Customer Charge per month $17,118.72

Transmission Charge per kW $1.39

Distribution Charge per kW $0.75

Non-Bypassable Transition Charge per kWh 1.150(cent)

Transmission Adjustment Factor per kWh 0.068(cent)

Distribution Charge per kWh* 0.396(cent)

Conservation and Load Management Adjustment per kWh 0.230(cent)(Eff. Jan. 1, 1997)

Additional Delivery Rates for Blackstone Valley Zone

Zonal Transition Factor per kWh 0.890(cent)

Transmission Adjustment Credit per kWh 0.042(cent)

Additional Delivery Rates for Newport Zone

Zonal Transition Factor per kWh 0.910(cent)

Transmission Adjustment Credit per kWh 0.064(cent)

Rates for Standard Offer Service or Last Resort Service (Optional)

Standard Offer per kWh 3.800(cent)(Eff. January 1, 2000)

Last Resort per kWh per Last Resort Service tariff

TAX NOTE: THE RATES LISTED ABOVE DO NOT REFLECT GROSS EARNINGS TAX OR SALES TAXES (WHEN APPLICABLE).
HOWEVER, SUCH TAXES, WHEN APPLICABLE, WILL APPEAR ON BILLS SENT TO CUSTOMERS.

Other Rate Clauses apply as usual.

</TABLE>

THE NARRAGANSETT ELECTRIC COMPANY
Effective
HIGH VOLTAGE RATE (H-72) April 1, 2000
High Voltage Delivery Service

R.I.P.U.C. No. 1123

Monthly Charge As Adjusted

Rates for High Voltage Delivery Service

<S> <C>
Customer Charge per month $63.75

Transmission Demand Charge per kW $1.34

Distribution Demand Charge per kW $0.35

Non-Bypassable Transition Charge per kWh 1.150(cent)

Transmission Adjustment Factor per kWh 0.068(cent)

Distribution Energy Charge per kWh* 0.396(cent)

Conservation and Load Management Adjustment per kWh 0.230(cent)(Eff. Jan. 1, 1997)

Additional Delivery Rates for Blackstone Valley Zone

Zonal Transition Factor per kWh 0.890(cent)

Transmission Adjustment Credit per kWh 0.042(cent)

Additional Delivery Rates for Newport Zone

Zonal Transition Factor per kWh 0.910(cent)

Transmission Adjustment Credit per kWh 0.064(cent)

Rates for Standard Offer Service or Last Resort Service (Optional)

Standard Offer per kWh 3.800(cent)(Eff. January 1, 2000)

Last Resort per kWh per Last Resort Service tariff

* Includes 0.068(cent)per kWh for phase-in of FAS 106 (Eff. Jan. 1, 1998), (0.038(cent)) per kWh for Rate Settlement
credit, 0.000(cent)per kWh for Standard Offer Adjustment Provision (Eff. Jan. 1, 2000) and 0.214(cent)per kWh and
0.152(cent)per kWh for Performance Based Rate Adjustment effective Jan. 1, 1997 and Jan. 1, 1998 respectively.

TAX NOTE: THE RATES LISTED ABOVE DO NOT REFLECT GROSS EARNINGS TAX OR SALES TAXES (WHEN APPLICABLE). HOWEVER,
SUCH TAXES, WHEN APPLICABLE, WILL APPEAR ON BILLS SENT TO CUSTOMERS.

Other Rate Clauses apply as usual.

</TABLE>

THE NARRAGANSETT ELECTRIC COMPANY Effective
69KV RATE (N-01) April 1, 2000
Retail Delivery Service

R.I.P.U.C. No.

Monthly Charge As Adjusted

Rates for Retail Delivery Service

<S> <C>
Distribution Charge per kW $5.52

Distribution Charge per kVAR $0.17

Non-Bypassable Transition Charge per kWh 1.150(cent)

Transmission Charge per kWh 0.408(cent)

Transmission Adjustment Factor per kWh 0.068(cent)

Distribution Charge per kWh* 0.574(cent)

Conservation and Load Management Adjustment per kWh 0.230(cent)(Eff. Jan. 1, 1997)

Additional Delivery Rates for Blackstone Valley Zone

Zonal Transition Factor per kWh 0.890(cent)

Transmission Adjustment Credit per kWh 0.042(cent)

Additional Delivery Rates for Newport Zone

Zonal Transition Factor per kWh 0.910(cent)

Transmission Adjustment Credit per kWh 0.064(cent)

Rates for Standard Offer Service or Last Resort Service (Optional)

Standard Offer per kWh 3.800(cent)(Eff. January 1, 2000)

Last Resort per kWh per Last Resort Service tariff

TAX NOTE: THE RATES LISTED ABOVE DO NOT REFLECT GROSS EARNINGS TAX OR SALES TAXES (WHEN APPLICABLE). HOWEVER,
SUCH TAXES, WHEN APPLICABLE, WILL APPEAR ON BILLS SENT TO CUSTOMERS.

Other Rate Clauses apply as usual.

</TABLE>

THE NARRAGANSETT ELECTRIC COMPANY Effective
LIMITED TRAFFIC SIGNAL SERVICE (R-02) April 1, 2000
Retail Delivery Service

R.I.P.U.C. No. 1110-A

Monthly Charge as Adjusted

Rates for Retail Delivery Service

<S> <C>
Non-Bypassable Transition Charge per kWh 1.150(cent)

Transmission Charge per kWh 0.259(cent)

Transmission Adjustment Factor per kWh 0.068(cent)

Distribution Charge per kWh* 0.867(cent)

Conservation and Load Management Adjustment per kWh 0.230(cent)(Eff. Jan. 1, 1997)

Rates for Standard Offer Service or Last Resort (Optional)

Standard Offer per kWh 3.800(cent)(Eff. January 1, 2000)

Last Resort per kWh per Last Resort Service tariff

TAX NOTE: THE RATES LISTED ABOVE DO NOT REFLECT GROSS EARNINGS TAX OR SALES TAXES (WHEN APPLICABLE). HOWEVER,
SUCH TAXES, WHEN APPLICABLE, WILL APPEAR ON BILLS SENT TO CUSTOMERS.

Other Rate Clauses apply as usual.
</TABLE>

THE NARRAGANSETT ELECTRIC COMPANY
Effective
LIMITED SERVICE - PRIVATE LIGHTING (S-10) April 1, 2000
Retail Delivery Service

R.I.P.U.C. No. 1111-A
Luminaire
Type/Lumens
Incandescent Code Annual kWh
- ------------ ----- ----------
<S> <C> <C> <C> <C>
1,000 10 440

Mercury Vapor

4,000 3 561
8,000 4 908
22,000 5 1,897
63,000 6 4,569
22,000 FL 23 1,897
63,000 FL 24 4,569

Sodium Vapor

4,000 70 248
9,600 72 490
27,500 74 1,284
50,000 75 1,968
27,500 FL 77 1,284
50,000 78 1,968

Non-Bypassable Transition Charge per kWh 1.150(cent)

Transmission Charge per kWh 0.259(cent)

Transmission Adjustment Factor per kWh 0.068(cent)

Distribution Energy Charge per kWh* 0.396(cent)

Conservation & Load Management Adjustment per kWh 0.230(cent)

Plus 3.800 cents per kWh for Standard Offer (Eff. January 1, 2000) (Optional)

Plus Last Resort per Last Resort Service tariff (Optional)

TAX NOTE: THE RATES LISTED ABOVE DO NOT REFLECT GROSS EARNINGS TAX OR SALES TAXES (WHEN APPLICABLE). HOWEVER,
SUCH TAXES, WHEN APPLICABLE, WILL APPEAR ON BILLS SENT TO CUSTOMERS.

Other Rate Clauses apply as usual.

</TABLE>

THE NARRAGANSETT ELECTRIC COMPANY
Effective
LIMITED STREET LIGHTING SERVICE (S-12) April 1, 2000
Retail Delivery Service

R.I.P.U.C. No. 1112-A
Luminaire
Type/Lumens Code Annual kWh

Incandescent
<S> <C> <C> <C>
1,000 50, 10 440
2,500 11 845

Mercury Vapor
4,000 3 561
8,000 4 908
8,000 (post top) 2 908
15,000 17, 18 1,874
22,000 5 1,897
22,000 (24 hr) 64 3,794
63,000 6 4,569

Sodium Vapor
4,000 70, 710, 711, 750, 755, 756 248
5,800 71 349
9,600 72, 79 490
27,500 74 1,284
50,000 75 1,968
27,500 (24 hr) 84 2,568
50,000 (FL) 78 1,968

Non-Bypassable Transition Charge per kWh 1.150(cent)

Transmission Charge per kWh 0.259(cent)

Transmission Adjustment Factor per kWh 0.068(cent)

Distribution Energy Charge per kWh* 0.396(cent)

Conservation & Load Management Adjustment per kWh 0.230(cent)

Plus 3.800 cents per kWh for Standard Offer (Eff. January 1, 2000) (Optional)

Plus Last Resort per Last Resort Service tariff (Optional)

* Includes 0.068(cent)per kWh for phase-in of FAS 106 (Eff. Jan. 1, 1998), (0.038(cent)) per kWh for Rate
Settlement credit, 0.000(cent)per kWh for Standard Offer Adjustment Provision (Eff. Jan. 1, 2000) and 0.214(cent)
per kWh and 0.152(cent)per kWh for Performance Based Rate Adjustments effective Jan. 1, 1997 and Jan. 1,
1998, respectively.

TAX NOTE: THE RATES LISTED ABOVE DO NOT REFLECT GROSS EARNINGS TAX OR SALES TAXES (WHEN APPLICABLE).
HOWEVER, SUCH TAXES, WHEN APPLICABLE, WILL APPEAR ON BILLS SENT TO CUSTOMERS.

Other Rate Clauses apply as usual.

</TABLE>

THE NARRAGANSETT ELECTRIC COMPANY Effective
GENERAL STREETLIGHTING SERVICE (S-14) April 1, 2000
Retail Delivery Service

R.I.P.U.C. No. 1113-A

Luminaire
Type/Lumens Code Annual kWh

Incandescent
1,000 10 440

Mercury Vapor
8,000 02 908
4,000 03 561
8,000 04 908
22,000 05 1,897
63,000 06 4,569

Sodium Vapor
4,000 70 248
9,600 72, 79 490
27,500 74 1,284
50,000 75 1,968
27,500 (24 hr) 84 2,568
50,000 FL 78 1,968

Narragansett Blackstone Newport
Zone Zone Zone
----------------------------------- ----------

<S> <C> <C> <C>
Non-Bypassable Transition Charge per kWh 1.150(cent) 1.150(cent) 1.150(cent)
Zonal Transition Factor per kWh 0.000(cent) 0.890(cent) 0.910(cent)
Distribution Energy Charge per kWh* 0.396(cent) 0.396(cent) 0.396(cent)
Transmission Charge per kWh 0.259(cent) 0.259(cent) 0.259(cent)
Transmission Adjustment Factor per kWh 0.068(cent) 0.068(cent) 0.068(cent)
Transmission Adjustment Credit per kWh 0.000(cent) 0.042(cent) 0.064(cent)
Conservation & Load Management Adj. Per kWh 0.230(cent) 0.230(cent) 0.230(cent)
Streetlight Credit per kWh 0.000(cent) 4.420(cent) 2.918(cent)

Plus 3.800 cents per kWh for Standard Offer (Eff. April 1, 2000) (Optional)

Plus Last Resort per Last Resort Service tariff (Optional)

* Includes 0.068(cent)per kWh for phase-in of FAS 106 (Eff. Jan. 1, 1998), (0.038(cent)) per kWh for Rate
Settlement credit, 0.000(cent)per kWh for Standard Offer Adjustment Provision (Eff. Jan. 1, 2000) and 0.214(cent)
per kWh and 0.152(cent)per kWh for Performance Based Rate Adjustments effective Jan. 1, 1997 and Jan. 1,
1998, respectively.

TAX NOTE: THE RATES LISTED ABOVE DO NOT REFLECT GROSS EARNINGS TAX OR SALES TAXES (WHEN APPLICABLE).
HOWEVER, SUCH TAXES, WHEN APPLICABLE, WILL APPEAR ON BILLS SENT TO CUSTOMERS.

Other Rate Clauses apply as usual.
</TABLE>

THE NARRAGANSETT ELECTRIC COMPANY Effective
LIMITED SERVICE ALL-ELECTRIC LIVING (T-06) April 1, 2000
Retail Delivery Service

R.I.P.U.C. No. 1114-A

Monthly Charge As Adjusted

Rates for Retail Delivery Service

<S> <C>
Customer Charge per month $7.84

Non-Bypassable Transition Charge per kWh 1.150(cent)

Transmission Charge per kWh 0.361(cent)

Transmission Adjustment Factor per kWh 0.068(cent)

Distribution Charge per kWh* 2.247(cent)

Minimum Charge per month $7.84

Conservation and Load Management Adjustment per kWh 0.230(cent)(Eff. Jan. 1, 1997)

Rates for Standard Offer Service or Last Resort Service (Optional)

Standard Offer per kWh 3.800(cent)(Eff. January 1, 2000)

Last Resort per kWh per Last Resort Service tariff

* Includes 0.068(cent)per kWh for phase-in of FAS 106 (Eff. Jan. 1, 1998), (0.038(cent)) per kWh for Rate
Settlement credit, 0.000(cent)per kWh for Standard Offer Adjustment Provision (Eff. Jan. 1, 2000) and 0.214(cent)
per kWh and 0.152(cent)per kWh for Performance Based Rate Adjustments effective Jan. 1, 1997 and Jan. 1,
1998, respectively.

TAX NOTE: THE RATES LISTED ABOVE DO NOT REFLECT GROSS EARNINGS TAX OR SALES TAXES (WHEN APPLICABLE).
HOWEVER, SUCH TAXES, WHEN APPLICABLE, WILL APPEAR ON BILLS SENT TO CUSTOMERS.

Other Rate Clauses apply as usual.

</TABLE>

THE NARRAGANSETT ELECTRIC COMPANY Effective
LIMITED SERVICE - BUSINESS SPACE HEATING (V-02) April 1, 2000
Retail Delivery Service

R.I.P.U.C. No. 1115-A

Monthly Charge As Adjusted

Rates for Retail Delivery Service

<S> <C>
Customer Charge per month $7.85

Non-Bypassable Transition Charge per kWh 1.150(cent)

Transmission Charge per kWh 0.547(cent)

Transmission Adjustment Factor per kWh 0.068(cent)

Distribution Charge per kWh* 3.038(cent)

Minimum Charge per month $7.85

Conservation and Load Management Adjustment per kWh 0.230(cent)(Eff. Jan. 1, 1997)

Rates for Standard Offer Service or Last Resort Service (Optional)

Standard Offer or Last Resort per kWh 3.800(cent)(Eff. January 1, 2000)

Last Resort per kWh per Last Resort Service tariff

* Includes 0.068(cent)per kWh for phase-in of FAS 106 (Eff. Jan. 1, 1998), (0.038(cent)) per kWh for Rate
Settlement credit, 0.000(cent)per kWh for Standard Offer Adjustment Provision (Eff. Jan. 1, 2000) and 0.214(cent)
per kWh and 0.152(cent)per kWh for Performance Based Rate Adjustments effective Jan. 1, 1997 and Jan. 1,
1998, respectively.

TAX NOTE: THE RATES LISTED ABOVE DO NOT REFLECT GROSS EARNINGS TAX OR SALES TAXES (WHEN APPLICABLE).
HOWEVER, SUCH TAXES, WHEN APPLICABLE, WILL APPEAR ON BILLS SENT TO CUSTOMERS.

Other Rate Clauses apply as usual.

</TABLE>

THE NARRAGANSETT ELECTRIC COMPANY
Effective
ELECTRIC PROPULSION RATE (X-01) April 1, 2000
High Voltage Delivery Service

R.I.P.U.C. No. 1121

Monthly Charge As Adjusted

Rates for High Voltage Delivery Service

<S> <C>
Customer Charge per month $10,000

Transmission Demand Charge per kW $1.34

Non-Bypassable Transition Charge per kWh 1.150(cent)

Transmission Adjustment Factor per kWh 0.068(cent)

Distribution Energy Charge per kWh* 0.396(cent)

Conservation and Load Management Adjustment per kWh 0.230(cent)

Additional Delivery Rates for Blackstone Valley Zone

Zonal Transition Factor per kWh 0.890(cent)

Transmission Adjustment Credit per kWh 0.042(cent)

Additional Delivery Rates for Newport Zone

Zonal Transition Factor per kWh 0.910(cent)

Transmission Adjustment Credit per kWh 0.064(cent)

Rates for Standard Offer Service or Last Resort Service (Optional)

Standard Offer per kWh 3.800(cent)(Eff. January 1, 2000)

Last Resort per kWh per Last Resort Service tariff

* Includes 0.068(cent)per kWh for phase-in of FAS 106 (Eff. Jan. 1, 1998), (0.038(cent)) per kWh for Rate Settlement
credit, 0.000(cent)per kWh for Standard Offer Adjustment Provision (Eff. Jan. 1, 2000) and 0.214(cent)per kWh and
0.152(cent)per kWh for Performance Based Rate Adjustment effective Jan. 1, 1997 and Jan. 1, 1998 respectively.

TAX NOTE: THE RATES LISTED ABOVE DO NOT REFLECT GROSS EARNINGS TAX OR SALES TAXES (WHEN APPLICABLE). HOWEVER,
SUCH TAXES, WHEN APPLICABLE, WILL APPEAR ON BILLS SENT TO CUSTOMERS.

Other Rate Clauses apply as usual.
</TABLE>

EXHIBIT 3

THE NARRAGANSETT ELECTRIC COMPANY Effective
LIMITED MEDIUM SECONDARY VOLTAGE C&I RATE (G-22) April 1, 2000
Retail Delivery Service

R.I.P.U.C. No.

Monthly Charge As Adjusted

Rates for Retail Delivery Service

<S> <C>
Distribution Charge per kW $1.50

Non-Bypassable Transition Charge per kWh 1.150(cent)

Transmission Charge per kWh 0.386(cent)

Transmission Adjustment Factor per kWh 0.079(cent)

Distribution Charge per kWh* 2.215(cent)

Conservation and Load Management Adjustment per kWh 0.230(cent)(Eff. Jan. 1, 1997)

Additional Delivery Rates for Blackstone Valley Zone

Zonal Transition Factor per kWh 0.970(cent)

Transmission Adjustment Credit per kWh 0.187(cent)

Additional Delivery Rates for Newport Zone

Zonal Transition Factor per kWh 0.990(cent)

Transmission Adjustment Credit per kWh 0.214(cent)

Rates for Standard Offer Service or Last Resort Service (Optional)

Standard Offer per kWh 3.800(cent)(Eff. January 1, 2000)

Last Resort per kWh per Last Resort Service tariff

* Includes 0.068(cent)per kWh for phase-in of FAS 106 (Eff. Jan. 1, 1998), 0.000(cent)per kWh for Standard OffeR
Adjustment Provision (Eff. Jan. 1, 2000) and 0.214(cent)per kWh and 0.152(cent)per kWh for Performance Based
Rate Adjustments effective Jan. 1, 1997 and Jan. 1, 1998, respectively.

TAX NOTE: THE RATES LISTED ABOVE DO NOT REFLECT GROSS EARNINGS TAX OR SALES TAXES. HOWEVER, SUCH TAXES, WHEN
APPLICABLE, WILL APPEAR ON BILLS SENT TO CUSTOMERS.

Other Rate Clauses apply as usual.
</TABLE>

R.I.P.U.C. No.
Sheet 1

THE NARRAGANSETT ELECTRIC COMPANY
LIMITED MEDIUM SECONDARY VOLTAGE C&I RATE (G-22)
RETAIL DELIVERY SERVICE

AVAILABILITY

This rate is limited only to those customers placed on this rate by
the Company and were formerly served under the Newport Electric or
Blackstone Valley Electric Rate G-2. Customers may change to another rate
if their demand is 500 kW or more, or less than 10 kW. This rate is closed
to all other customers.

MONTHLY CHARGE

The Monthly Charge will be the sum of the Retail Delivery Service
Charges set forth in the cover sheet of this tariff.

RATE ADJUSTMENT PROVISIONS

Transmission Service Charge Adjustment

The prices under this rate as set forth under "Monthly Charge" may be
adjusted from time to time in the manner described in the Company's
Transmission Service Cost Adjustment Provision.

Transition Charge Adjustment

The prices under this rate as set forth under "Monthly Charge" may be
adjusted from time to time in the manner described in the Company's
Non-Bypassable Transition Charge Adjustment Provision.

Standard Offer Adjustment

All Customers served on this rate must pay any charges required
pursuant to the terms of the Company's Standard Offer Adjustment
Provisions, whether or not the Customer is taking or has taken Standard
Offer Service.

Conservation and Load Management Adjustment

The amount determined under the preceding provisions shall be
adjusted in accordance with the Company's Conservation and Load Management
Adjustment Provision as from time to time effective in accordance with law.

Performance Based Rate Adjustment

The amount determined under the preceding provisions shall be
adjusted periodically in accordance with Section 39-1-27.5 of the Rhode
Island General Laws.

STANDARD OFFER SERVICE

Any Customer served under this rate who is eligible for Standard
Offer Service shall receive such service pursuant to the Standard Offer
Service tariff.

LAST RESORT SERVICE

Any Customer served under this rate who does not take its power
supply from a non-regulated power producer and is ineligible for Standard
Offer Service will receive Last Resort Service pursuant to the Last Resort
Service tariff.

DETERMINATION OF BILLING DEMAND

The Billing Demand in kilowatts for each month will be the lower of
the maximum metered demand in any fifteen-minute period during the month or
the month energy consumption divided by 150.

POWER FACTOR ADJUSTMENT

Customers who have established a Billing Demand of 100 kilowatts or
more in the current or preceding eleven months will receive a Power Factor
Adjustment (PFA) to their Demand Charge based on the following method,
except that the Demand Charge shall not be less than 95% nor more than 110%
of the Demand Charge before adjustment:

PFA = ((0.80 / Power Factor) - 1) x (Unadjusted Demand Charge / 3)

GROSS EARNINGS TAX

A Rhode Island Gross Earnings Tax adjustment will be applied to the
charges determined above in accordance with Rhode Island General Laws.

GROSS EARNINGS TAX CREDIT FOR MANUFACTURERS

Consistent with the gross receipts tax exemption provided in Section
44-13-35 of Rhode Island General Laws, eligible manufacturing customers
will be exempt from the Gross Earnings Tax to the extent allowed by the
Division of Taxation.

Eligible manufacturing customers are those customers who have on file
with the Company a valid certificate of exemption from the Rhode Island
sales tax (under section 44-18-30(H) of Rhode Island General Laws)
indicating the customer's status as a manufacturer. If the Division of
Taxation (or other Rhode Island taxing authority with jurisdiction)
disallows any part or all of the exemption as it applies to a customer, the
customer will be required to reimburse the Company in the amount of the
credits provided to such customer which were disallowed, including any
interest required to be paid by the Company to such authority.

TERMS AND CONDITIONS

The Company's Terms and Conditions in effect from time to time, where
not inconsistent with any specific provisions hereof, are a part of this
rate.

Effective: April 1, 2000

THE NARRAGANSETT ELECTRIC COMPANY Effective
69KV RATE (N-01) April 1, 2000
Retail Delivery Service

R.I.P.U.C. No.

Monthly Charge As Adjusted

Rates for Retail Delivery Service

<S> <C>
Distribution Charge per kW $5.52

Distribution Charge per kVAR $0.17

Non-Bypassable Transition Charge per kWh 1.150(cent)

Transmission Charge per kWh 0.408(cent)

Transmission Adjustment Factor per kWh 0.068(cent)

Distribution Charge per kWh* 0.574(cent)

Conservation and Load Management Adjustment per kWh 0.230(cent)(Eff. Jan. 1, 1997)

Additional Delivery Rates for Blackstone Valley Zone

Zonal Transition Factor per kWh 0.890(cent)

Transmission Adjustment Credit per kWh 0.042(cent)

Additional Delivery Rates for Newport Zone

Zonal Transition Factor per kWh 0.910(cent)

Transmission Adjustment Credit per kWh 0.064(cent)

Rates for Standard Offer Service or Last Resort Service (Optional)

Standard Offer per kWh 3.800(cent)(Eff. January 1, 2000)

Last Resort per kWh per Last Resort Service tariff

TAX NOTE: THE RATES LISTED ABOVE DO NOT REFLECT GROSS EARNINGS TAX
OR SALES TAXES (WHEN APPLICABLE). HOWEVER, SUCH TAXES, WHEN
APPLICABLE, WILL APPEAR ON BILLS SENT TO CUSTOMERS.

Other Rate Clauses apply as usual.
</TABLE>

R.I.P.U.C. No.
Sheet 1
Cancelling R.I.P.U.C. No.

THE NARRAGANSETT ELECTRIC COMPANY
69KV RATE (N-01)
RETAIL DELIVERY SERVICE

AVAILABILITY

This rate is available to customers taking service at a nominal
voltage of 69,000 volts and is mandatory for the Department of the Navy,
its successors, or assigns, for electric power service to the Naval
Education and Training Center, Newport, Rhode Island.

Electric retail delivery service supplied hereunder shall be three
phase, alternating current, at a nominal frequency of sixty Hertz, and at a
nominal voltage of 69,000 volts.

MONTHLY CHARGE

The Monthly Charge will be the sum of the Retail Delivery Service
Charges set forth in the cover sheet of this tariff.

DETERMINATION OF BILLING PERIODS

The Billing Period consists of the days between consecutive meter
readings. Service under this Rate is rendered on a full calendar day basis.
The first day of any billing period is included in its entirety and the
last day of any billing period is excluded in its entirety.

DETERMINATION OF BILLING DEMANDS

I. Billing Demand

A. Requirements Service

The Demand in kilowatts for each month is the maximum metered
fifteen-minute demand during the Billing Period.

B. Partial Requirements Service

The Demand in kilowatts for each month is the maximum fifteen-minute
total demand during the month, where the total demand is the combined of
the Partial Requirements Service delivered by the Company and the service
supplied by the customer's other power source.

The Billing Demand in kilowatts for each month shall be the largest
of:

1. the Demand,

2. Seventy-five percent (75%) of the highest Demand recorded during
the previous eleven months, or

3. Fifty percent (50%) of the highest Demand recorded by the customer
since 1961, where:

For the purposes of determining the Billing Demand, all demands
recorded before December 1, 1994, shall be deemed Demands, all Standby
Demands recorded after December 1, 1994, through June 30, 1997 shall be
deemed Demands, and all Distribution Demands recorded after June 30, 1997,
shall be deemed Demands.

II. Reactive Billing Demand

The Reactive Billing Demand in kilovars for each month shall be the
Reactive Demand in excess of seventeen and one-half percent (17.5%) of the
Demand, where the Reactive Demand in kilovars for each month is the metered
fifteen-minute reactive demand coincident with the Demand.

DETERMINATION OF BILLING DEMAND CHARGES

I. Billing Demand Charge

The Billing Demand Charge shall be the Billing Demand times the
Demand Rate.

I. Reactive Billing Demand Charge

The Reactive Billing Demand Charge shall be the Reactive Billing
Demand times the Reactive Demand Rate.

DETERMINATION OF MINIMUM BILLING ENERGY CHARGE

The Minimum Billing Energy Charge shall be the Total Energy
Requirements times the Transition Charge. For the purposes of the
foregoing, Total Energy Requirements shall mean the sum of the energy
delivered by the Company and the energy supplied by the Navy's other power
sources other than electrically isolated emergency power sources.

RATE ADJUSTMENT PROVISIONS

Transmission Service Charge Adjustment

The prices under this rate as set forth under "Monthly Charge" may be
adjusted from time to time in the manner described in the Company's
Transmission Service Cost Adjustment Provision.

Transition Charge Adjustment

The prices under this rate as set forth under "Monthly Charge" may be
adjusted from time to time in the manner described in the Company's
Non-Bypassable Transition Charge Adjustment Provision.

Standard Offer Adjustment

Conservation and Load Management Adjustment

Performance Based Rate Adjustment

The amount determined under the preceding provisions shall be
adjusted periodically in accordance with Section 39-1-27.5 of the Rhode
Island General Laws.

STANDARD OFFER SERVICE

Any Customer served under this rate who is eligible for Standard
Offer Service shall receive such service pursuant to the Standard Offer
Service tariff.

LAST RESORT SERVICE

GROSS EARNINGS TAX

A Rhode Island Gross Earnings Tax adjustment will be applied to the
charges determined above in accordance with Rhode Island General Laws.

GROSS EARNINGS TAX CREDIT FOR MANUFACTURERS

DEFINITIONS OF TERMS

"Requirements Service" means that the Company delivers all the energy
and capacity necessary to meet the total electric service requirements of
the Navy, other than electric service requirements provided by electrically
isolated emergency power sources.

"Partial Requirements Service" means Supplementary Service, Backup
Service, and Maintenance Service, either individually or in any
combination.

"Supplementary Service" means electric energy and capacity delivered
by the Company on a regular basis in addition to that which is normally
provided by the Navy's other power source.

"Backup Service" means electric energy and capacity delivered by the
Company to replace energy and capacity ordinarily provided by the Navy's
other power source during an unscheduled outage of the power source.

"Maintenance Service" means electric energy and capacity delivered by
the Company to replace energy and capacity ordinarily provided by the
Navy's other power source during a scheduled outage of the power source.

TERMS AND CONDITIONS

The Company's Terms and Conditions in effect from time to time, where
not inconsistent with any specific provisions hereof, are a part of this
rate.

Effective: April 1, 2000

R.I.P.U.C. No. 1102-A
Sheet 1
Cancelling R.I.P.U.C. No. 1079

THE NARRAGANSETT ELECTRIC COMPANY
RESIDENTIAL TIME-OF-USE RATE (A-32)
RETAIL DELIVERY SERVICE

AVAILABILITY

Electric delivery service under this rate is available for all
domestic purposes in an individual private dwelling or an individual
private apartment. Service is also available for farm customers where
delivery is provided by the Company. A church and adjacent buildings owned
and operated by the church may be served under this rate, but any such
buildings separated by public ways must be billed separately.

The Company may under unusual circumstances permit more than one set
of living quarters to be served through one metering installation under
this rate, but if so, the Customer Charge shall be multiplied by the number
of separate living quarters so served.

The Company will require any Customer taking service on the Basic
Residential Rate A-16 or the Residential Water Heater Control Rate A-18 to
take service on this rate if the Customer's usage for the previous 12
months exceeds 30,000 kWh. The Company will require any new customer to
take service under this rate if the Company estimates that the Customer's
annual usage will exceed 30,000 kWh. A Customer who has been placed on this
rate pursuant to this paragraph may transfer to another available rate if
the Customer's usage for the previous 12 months is less than 24,000 kWh.

FARM CUSTOMER EXEMPTION

Any customer taking service under the Company's the Basic Residential
Rate A-16 or the Residential Water Heater Control Rate A-18 who qualifies
as a "farm customer" may be exempted from taking delivery under this rate,
even if such customer's annual usage exceeds 30,000 kWh.

Customers seeking a Farm Customer Exemption have the burden of
providing documentation of their "farm customer status" to the Company. A
document such as a Federal 1040-F form will be accepted by the Company as
reasonable documentation of such status. Customers may be required by the
Company to qualify for the exemption on an annual basis.

MONTHLY CHARGE

The Monthly Charge will be the sum of the applicable Retail Delivery
Service Charges set forth in the cover sheet of this tariff.

Customers placed on this rate by the Company without time of use
meters shall not be required to pay the Time of Use Metering Charge.

PEAK AND OFF-PEAK PERIODS

Peak Hours: October - April -- 8 a.m. - 12 p.m. Weekdays
4 p.m. - 8 p.m. Weekdays

May - September -- 10 a.m. - 4 p.m. Weekdays

Off-Peak Hours: All other hours

Weekdays shall mean Monday through Friday, excluding the following
holidays: New Years' Day, President's Day, Memorial Day, Independence Day,
Columbus Day (observed), Labor Day, Veteran's Day, Thanksgiving Day and
Christmas Day.

RATE ADJUSTMENT PROVISIONS

Transmission Service Charge Adjustment

The prices under this rate as set forth under "Monthly Charge" may be
adjusted from time to time in the manner described in the Company's
Transmission Service Cost Adjustment Provision.

Transition Charge Adjustment

The prices under this rate as set forth under "Monthly Charge" may be
adjusted from time to time in the manner described in the Company's
Non-Bypassable Transition Charge Adjustment Provision.

Standard Offer Adjustment

Conservation and Load Management Adjustment

Performance Based Rate Adjustment

The amount determined under the preceding provisions shall be
adjusted periodically in accordance with Section 39-1-27.5 of the Rhode
Island General Laws.

STANDARD OFFER SERVICE

Any Customer served under this rate who is eligible for Standard
Offer Service shall receive such service pursuant to the Standard Offer
Service tariff.

LAST RESORT SERVICE

MINIMUM CHARGE

The monthly minimum charge shall be the sum of the monthly Customer
Charge plus the monthly time-of-use Metering Charge.

GROSS EARNINGS TAX

A Rhode Island Gross Earnings Tax adjustment will be applied to the
charges determined above in accordance with Rhode Island General Laws.

TERMS AND CONDITIONS

The Company's Terms and Conditions in effect from time to time where
not inconsistent with any specific provisions hereof, are a part of this
rate.

Effective: April 1, 2000

R.I.P.U.C. No. 1103-A
Sheet 1
Cancelling R.I.P.U.C. No. 1083

THE NARRAGANSETT ELECTRIC COMPANY
LOW INCOME RATE (A-60)
RETAIL DELIVERY SERVICE

AVAILABILITY

Service under this rate is available only to currently qualified
customers for all domestic purposes in an individual private dwelling or an
individual apartment, providing such customer meets both of the following
criteria:

1. Must be the head of a household or principal wage earner.
2. Must be presently receiving Supplemental Security Income from
the Social Security Administration, be eligible for the
low-income home energy assistance program, or one of the
following from the appropriate Rhode Island agencies: Medicaid,
Food Stamps, General Public Assistance or Aid to Families with
Dependent Children.

It is the responsibility of the customer to annually certify, by
forms provided by the Company, the continued compliance with the foregoing
provisions.

The Company may under unusual circumstances permit more than one set
of living quarters to be served through one meter under this rate, but if
so, the kilowatt-hours eligible for the credit described below shall be
multiplied by the number of separate living quarters so served.

MONTHLY CHARGE

The Monthly Charge will be the sum of the applicable Retail Delivery
Service Charges set forth in the cover sheet sheet of this tariff.

Provided, however, that any customer who installed prior to January
1, 1998 and has in regular operation an electric water heater of a type
approved by the Company and conforming to the Conditions for Electric Water
Heating contained herein, shall receive a credit of 0.661(cent) per kWh for
the first 750 kWh per month.

RATE ADJUSTMENT PROVISIONS

Transmission Service Charge Adjustment

The prices under this rate as set forth under "Monthly Charge" may be
adjusted from time to time in the manner described in the Company's
Transmission Service Cost Adjustment Provision.

Transition Charge Adjustment

The prices under this rate as set forth under "Monthly Charge" may be
adjusted from time to time in the manner described in the Company's
Non-Bypassable Transition Charge Adjustment Provision.

Standard Offer Adjustment

Conservation and Load Management Adjustment

STANDARD OFFER SERVICE

Any Customer served under this rate who is eligible for Standard
Offer Service shall receive such service pursuant to the Standard Offer
Service tariff.

LAST RESORT SERVICE

CONDITIONS FOR ELECTRIC WATER HEATING

1. Electricity will be the only source of energy for water heating.

2. The Company reserves the right to limit the operation of the
bottom water heating element, but in no case shall operation be
less than 16 hours a day, or a total of 126 hours per week.

3. All water heaters installed after January 1, 1968 shall have a
storage capacity of 80 gallons or greater and be of a type
approved by the Company, except as provided below.

4. Approved water heaters of less than 80 gallons now being served by
the Company may be permitted to transfer to this rate, and at the
Company's option, smaller tanks may be permitted only within an
individual apartment of a multi-family building.

5. The customer shall provide a separate circuit for the water
heater, of ample capacity and designed for 240-volt operation, to
which no equipment other than the water heater shall be connected.

GROSS EARNINGS TAX

A Rhode Island Gross Earnings Tax adjustment will be applied to the
charges determined above in accordance with Rhode Island General Laws.

TERMS AND CONDITIONS

The Company's Terms and Conditions in effect from time to time, where
not inconsistent with any specific provisions hereof, are a part of this
rate.

Effective: April 1, 2000

THE NARRAGANSETT ELECTRIC COMPANY Narragansett Electric
Illustrative Calculation of First Look Savings Proof - 2002 Test Year BVE/Newport Electric
Company Filing in 2003 Using Historical 2002 Data R.I.P.U.C. No. 2930

($ MILLIONS) Settlement Exhibit 4a

Formula for First Look Proven Savings:

Proven Savings = Adjusted Benchmark COS - 2002 COS + .3 * (Adjusted Benchmark COS *
Weather Normalized Sales Growth)

Line Amount
<S> <C> <C> <C>
1 Benchmark Cost of Service 210.000
2
3 GDPIPD Growth 2001 1.60% * 50% 1.0080
------
4
5 2001 Adjusted Benchmark COS 211.680
6
7 GDPIPD Growth 2002 1.70% * 50% 1.0085
------
8
9 2002 Adjusted Benchmark COS 213.479
10
11 2000 kWh Sales from Settlement 7,098,202,000
12
13 Weather Adjusted 2002 kWh Sales 7,240,875,860
14
15 Weather Normalized Sales Growth 2.010%
16
17 Adjusted Sales Growth 2.01% 213.479 1.287
18
19 Normalized Cost of Service - 2002 Test Year 206.654
20
21 Savings to be Shared 8.112
22
23 50/50 Sharing of Proven Savings 4.056

Line 1 Per Division Adjusted Cost of Service
Line 3 For purposes of this illustration DRI estimated Annual
change in Implicit GDP Deflator. Actual change will be used
Line 5 Line 1 * Line 3
Line 7 For purposes of this illustration DRI estimated Annual
change in Implicit GDP Deflator. Actual change will be used
Line 9 Line 5 * Line 7
Line 11 Per JMM-15, JJB-2a and JJB-2b adjusted for Division
adjustment.
Line 13 For purposes of this illustration, Line 11 escalated by
1% weather adjusted sales growth for for two years. Actual
weather adjusted sales will be used
Line 15 (Line 13 - Line 11) / Line 11
Line 17 lINE 9 * line 15 * 30%
Line 19 For this illustration, the Normalized COS was assumed to be
$206,654,000. Actual filed COS will be used.
Line 21 Line 9 + Line 17 - Line 19
Line 23 50% of Line 21

</TABLE>

<TABLE>
<CAPTION>
THE NARRAGANSETT ELECTRIC COMPANY Narragansett Electric
Illustrative Calculation of Second Look Savings Proof - 2005 Rate Year BVE/Newport Electric
Company Files COS Rate Case in 2004 using Historical 2003 Data - Rate Year 2005 R.I.P.U.C. No. 2930

($ MILLIONS) Settlement Exhibit 4b

Formula for Second Look Proven Savings:

Proven Savings = Adjusted Benchmark COS - 2005 COS + .3 * (Adjusted Benchmark COS *
Weather Normalized Sales Growth)

Line Amount

<S> <C> <C> <C>
1 Benchmark Cost of Service 210.000
2
3 GDPIPD Growth 2001 1.60% * 50% 1.0080
4 2001 Adjusted Benchmark COS 211.680
5 GDPIPD Growth 2002 1.70% * 50% 1.0085
6 2002 Adjusted Benchmark COS 213.479
7 GDPIPD Growth 2003 2.00% * 50% 1.0100
8 2003 Adjusted Benchmark COS 215.614
9 GDPIPD Growth 2004 2.00% * 50% 1.0100
10 2004 Adjusted Benchmark COS 217.770
11 GDPIPD Growth 2005 2.20% * 50% 1.0110
12 2005 Adjusted Benchmark COS 220.166
13
14 2000 kWh Sales from Settlement 7,098,202,000
15
16 Weather Adjusted 2005 kWh Sales 7,460,281,640
17
18 Weather Normalized Sales Growth 5.101%
19
20 Adjusted Sales Growth 5.10% * 30% 220.166 3.369
21
22 Normalized Cost of Service - 2005 Rate Year 214.240
23
24 Savings to be Shared 9.295
25
26 50/50 Sharing of Proven Savings 4.647
27
28 Shared Savings Cap 4.183

Line 1 Per Division Adjusted Cost of Service
Lines 3, 5, 7, 9, 11
For purposes of this illustration DRI estimated Annual
change in Implicit GDP Deflator. Actual change will be
used.
Line 4 Line 1 * Line 3
Line 6 Line 4 * Line 5
Line 8 Line 6 * Line 7
Line 10 Line 8 * Line 9
Line 12 Line 10 * Line 11
Line 14 Per JMM-15, JJB-2a and JJB-2b adjusted for Division
adjustment.
Line 16 For purposes of this illustration, Line 14 escalated
by 1% weather adjusted sales growth for for five years.
Actual weather adjusted sales will be used
Line 18 (Line 16 - Line 14) / Line 14
Line 20 Line 12 * Line 18 *30%
Line 22 For this illustration, the Normalized COS was assumed to be $214,240,000. Actual
filed COS will be used.
Line 24 Line 12 + Line 20 - Line 22
Line 26 50% of Line 24
Line 28 Minimum of Line 26 or Exhibit 4a, Line 23 inflated @ 50% of GDPIPD

</TABLE>

<TABLE>
<CAPTION>
THE NARRAGANSETT ELECTRIC COMPANY Narragansett Electric
Illustrative Calculation of Second Look Savings Proof - 2006 Test Year BVE/Newport Electric
Company Filing in 2007 Using Historical 2006 Data R.I.P.U.C. No. 2930
Revised
($ MILLIONS) Settlement Exhibit 4c

Formula for Second Look Proven Savings:

Proven Savings = Adjusted Benchmark COS - 2006 COS + .3 * (Adjusted Benchmark COS *
Weather Normalized Sales Growth)

Line Amount

<S> <C> <C> <C>
1 Benchmark Cost of Service 210.000
2
3 GDPIPD Growth 2001 1.60% * 50% 1.0080
4 2001 Adjusted Benchmark COS 211.680
5 GDPIPD Growth 2002 1.70% * 50% 1.0085
6 2002 Adjusted Benchmark COS 213.479
7 GDPIPD Growth 2003 2.00% * 50% 1.0100
8 2003 Adjusted Benchmark COS 215.614
9 GDPIPD Growth 2004 2.00% * 50% 1.0100
10 2004 Adjusted Benchmark COS 217.770
11 GDPIPD Growth 2005 2.20% * 50% 1.0110
12 2005 Adjusted Benchmark COS 220.166
13 GDPIPD Growth 2006 2.20% * 50% 1.0110
14 2006 Adjusted Benchmark COS 222.588
15
16 2000 kWh Sales from Settlement 7,098,202,000
17
18 Forecasted 2006 kWh Sales 7,534,884,456
19
20 Weather Normalized Sales Growth 6.152%
21
22 Adjusted Sales Growth 6.15% 222.588 4.108 ______ 0.3
23
24 Normalized Cost of Service - 2006 Test Year 218.953
25
26 Savings to be Shared 7.742
27
28 50/50 Sharing of Proven Savings 3.871
29
30 Shared Savings Cap 3.871

Line 1 Per Division Adjusted Cost of Service
Lines 3, 5, 7, 9, 11, 13
For purposes of this illustration DRI estimated Annual
change in Implicit GDP Deflator. Actual change will be
used.
Line 4 Line 1 * Line 3
Line 6 Line 4 * Line 5
Line 8 Line 6 * Line 7
Line 10 Line 8 * Line 9
Line 12 Line 10 * Line 11
Line 14 Line 12 * Line 13
Line 16 Per JMM-15, JJB-2a and JJB-2b adjusted for Division
adjustment.
Line 18 For purposes of this illustration, Line 16 escalated by 1% weather adjusted sales
growth for for six years. Actual weather adjusted sales will be used
Line 20 (Line 18 - Line 16) / Line 16
Line 22 Line 14 * Line 30 * 30%
Line 24 For this illustration, the Normalized COS was assumed to be $218,953,000. Actual
filed COS will be used.
Line 26 Line 14 + Line 22 - Line 24
Line 28 50% of Line 26
Line 30 Minimum of Line 28 or Exhibit 4a, Line 23 inflated @ 50% of GDPIPD

</TABLE>

EXHIBIT 5
THE NARRAGANSETT ELECTRIC COMPANY Narragansett Electric
BVE/Newport Electric
Illustrative Examples of Reopener on Proof of Savings R.I.P.U.C. No. 2930

1 GDPIPD Growth Assumptions
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
2 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
3
4 GDPIPD Growth
1.70% 1.60% 1.70% 2.00% 2.00% 2.20% 2.20% 2.20% 2.30% 2.30% 2.20% 2.50% 2.50% 2.50% 2.70% 2.90% 3.10% 3.40% 3.60% 3.80%
5 80% GDPIPD Growth
1.76% 2.00% 2.00% 2.00% 2.16% 2.32% 2.48% 2.72% 2.88% 3.04%
6 Settled Rate Freeze Esc 1.90% 1.90% 1.90% 1.90% 1.90%
7
8 kWh Growth Assumption (1%)
7,098,202 7,169,184 7,240,876 7,313,285 7,386,417 7,460,282 7,534,884 7,610,233 7,686,336 7,763,199 7,840,831 7,919,239
7,998,432 8,078,416 8,159,200 8,240,792 8,323,200 8,406,432 8,490,496 8,575,401
9
10 Reopener Thresholds
11
12 Cumulative Reopener Threshold
0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 1.90% 3.80% 5.70% 7.60% 9.50% 11.26% 13.26% 15.26% 17.26% 19.42% 21.74% 24.22% 26.94% 29.82%
13 Cumulative GDPIPD Threshold
0.00%1.70% 3.30%5.00% 7.00% 9.00% 11.20% 13.40% 15.60% 17.90% 20.20% 22.40% 24.90% 27.40% 29.90% 19.42% 21.74% 24.22% 26.94%29.82%
14
15 Illustration 1 - Company demonstrates ROE less than 10.50% for 2003 curtailing settlement credit as of January 1, 2004 and
files a Cost of Service of $225.000 million effective January 1, 2006.
16
17 Benchmark COS Rev Req 210,000 210,000 210,000 210,000 210,000
18
19 Hold Harmless (425) 0
20 Settlement Credit (2,700) 0
21 LIHEAP Expansion (575) 0
22 75% of January 1, 2005 increase 0
23 Total 210,000
24
25 kWh Conversion
26 Benchmark COS (cents) 2.958 2.958
27 Hold Harmless (cents) (0.006) 0.000
28 Settlement Credit (cents) (0.038) 0.000
29 LIHEAP Expansion (cents] (0.008) 0.000
30 75% of January 1, 2005 increase
31 Avg Cents per kWh 2.906 2.958
32
33 Company Filed COS Rev Req for 2006 225,000
34
35 Rate Year Revenues @ Current rate 222,882
36
37 Revenue Change 2,118
38
39 Percent Revenue Change 0.95% (a)
40
41 Cumulative Reopener Threshold 1.90% (a)

(a) Cumulative Percentage Revenue Change is less than the
cumulative Reopener Threshold for 2006, continued existence of savings is
demonstrated.

Line 4 For purposes of the illustration, DRI estimated GDPIPD growth rates were used. Actual amounts will be used as available
Line 5 80% of Line 4
Line 6 Settled escalation rate for rate freeze period
Line 8 Estimated 2000 MWH per JMM-15, JJB-2a and JJB-2b adjusted for Division kWh adjustment escalated at 1%.
Line 12 Sum of annual amounts from Lines 6 and 5
Line 13 Sum of annual amounts from Line 4. For Years 2015 - 2019 equal to Cumulative reopener indexsame as Line 12
Line 17 Settled benchmark Cost of Service
Line 26 Line 17 divided by Line 8
Line 27 Line 19 divided by Line 8
Line 28 Line 20 divided by Line 8
Line 29 Line 21 divided by Line 8
Line 30 Line 22 divided by Line 8
Line 33 Total filed Cost of Service revenue requirement
Line 35 Rate Year kWh times then current average kWh Rate (Line 31)
Line 39 Line 37 divided by Line 35
</TABLE>

THE NARRAGANSETT ELECTRIC COMPANY Narragansett Electric
BVE/Newport Electric
Illustrative Examples of Reopener on Proof of Savings R.I.P.U.C. No. 2930

1 GDPIPD Growth Assumptions
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
2 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
3
4 Est GDPIPD Growth
1.70% 1.60% 1.70% 2.00% 2.00% 2.20% 2.20% 2.20% 2.30% 2.30% 2.20% 2.50% 2.50% 2.50% 2.70% 2.90% 3.10% 3.40% 3.60% 3.80%
5 80% GDPIPD Growth
1.76% 2.00% 2.00% 2.00% 2.16% 2.32% 2.48% 2.72% 2.88% 3.04%
6 Settled Rate Freeze Esc
1.90% 1.90% 1.90% 1.90% 1.90%
7
8 kWh Growth Assumption (1%)
7,098,202 7,169,184 7,240,876 7,313,285 7,386,417 7,460,282 7,534,884 7,610,233 7,686,336 7,763,199 7,840,831 7,919,239
7,998,432 8,078,416 8,159,200 8,240,792 8,323,200 8,406,432 8,490,496 8,575,401
9
10 Reopener Thresholds
11
12 Cumulative Reopener Threshold
0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 1.90% 3.80% 5.70% 7.60% 9.50% 11.26% 13.26% 15.26% 17.26% 19.42% 21.74% 24.22% 26.94% 29.82%
13 Cumulative GDPIPD Threshold
0.00% 1.70% 3.30% 5.00% 7.00% 9.00% 11.20% 13.40% 15.60% 17.90% 20.20% 22.40% 24.90% 27.40% 29.90% 19.42% 21.74% 24.22% 26.94%
29.82%
14
15 Illustration 2 - Company petitions for a $5.0 million increase effectice January 1, 2005 and files a Cost of Service of
$245.000 effective January 1, 2008.
16
17 Benchmark COS Rev Req 210,000 210,000 210,000 210,000 210,000
18
19 Hold Harmless (425) 0
20 Settlement Credit (2,700) 0
21 LIHEAP Expansion (575) 0
22 75% of January 1, 2005 increase 3,750
23 Total 213,750
24
25 kWh Conversion
26 Benchmark COS (cents) 2.958 2.958
27 Hold Harmless (cents) (0.006) 0.000
28 Settlement Credit (cents) (0.038) 0.000
29 LIHEAP Expansion (cents] (0.008) 0.000
30 75% of January 1, 2005 increase 0.051
31 Benchmark Avg Cents per kWh 3.009
32
33 Company Filed COS Rev Req 245,000
34
35 Rate Year Revenues at Current rate 231,282
36
37 Revenue Change 13,718
38
39 Percent Revenue Change 5.93% (a)
40
41 Cumulative Reopener Threshold 5.70% (a)
42
43 Cumulative GDPIPD Threshold 15.60% (a)

(a) Cumulative Percentage Revenue Change is more than the
cumulative Reopener Theshold for 2008 but less than cumulative GDPIPD
threshold for 2008, Company must demonstrate continued shared savings.

Line 4 DRI estimated GDPIPD growth rate

Line 5 80% of Line 4
Line 6 Settled escalation rate for rate freeze period

Line 8 Estimated 2000 MWH per JMM-15, JJB-2a and JJB-2b adjusted for Division kWh adjustment escalated at 1%.

Line 12 Sum of annual amounts from Lines 6 and 5

Line 13 Sum of annual amounts from Line 4. For Years 2015 - 2019 equal to Cumulative reopener indexsame as Line 12

Line 17 Settled benchmark Cost of Service

Line 26 Line 17 divided by Line 8
Line 27 Line 19 divided by Line 8
Line 28 Line 20 divided by Line 8
Line 29 Line 21 divided by Line 8
Line 30 Line 22 divided by Line 8
Line 33 Total filed Cost of Service revenue requirement

Line 35 Rate Year kWh times then current average kWh Rate (Line 31)

Line 39 Line 37 divided by Line 35

</TABLE>

<TABLE>
<CAPTION>
THE NARRAGANSETT ELECTRIC COMPANY Narragansett Electric
BVE/Newport Electric
Illustrative Examples of Reopener on Proof of Savings R.I.P.U.C. No. 2930

<S> <C>
1 GDPIPD Growth Assumptions
2 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
3
4 Est GDPIPD Growth
1.70% 1.60% 1.70% 2.00% 2.00% 2.20% 2.20% 2.20% 2.30% 2.30% 2.20% 2.50% 2.50% 2.50% 2.70% 2.90% 3.10% 3.40% 3.60% 3.80%
5 80% GDPIPD Growth
1.76% 2.00% 2.00% 2.00% 2.16% 2.32% 2.48% 2.72% 2.88% 3.04%
6 Settled Rate Freeze Esc
1.90% 1.90% 1.90% 1.90% 1.90%
7
8 kWh Growth Assumption (1%)
7,098,202 7,169,184 7,240,876 7,313,285 7,386,417 7,460,282 7,534,884 7,610,233 7,686,336 7,763,199 7,840,831 7,919,239
7,998,432 8,078,416 8,159,200 8,240,792 8,323,200 8,406,432 8,490,496 8,575,401
9
10 Reopener Thresholds
11
12 Cumulative Reopener Threshold
0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 1.90% 3.80% 5.70% 7.60% 9.50% 11.26% 13.26% 15.26% 17.26% 19.42% 21.74% 24.22% 26.94% 29.82%
13 Cumulative GDPIPD Threshold
0.00% 1.70% 3.30% 5.00% 7.00% 9.00% 11.20% 13.40% 15.60% 17.90% 20.20% 22.40% 24.90% 27.40% 29.90% 19.42% 21.74% 24.22% 26.94%
29.82%
14
15 Illustration 3 - Company's ROE for 2003 exceeds 10.50% and the Company
files Cost of Service of $233.300 million effective January 1, 2008,
$258.300 million effective January 1, 2011 and $295.300 million effective
January 1, 2016.
16
17 Benchmark COS Rev Req 210,000 210,000 210,000 210,000 210,000
18
19 Hold Harmless (425) 0
20 Settlement Credit (2,700) (2,700)
21 LIHEAP Expansion (575) 0
22 75% of January 1, 2005 increase 0
23 Total 207,300
24
25 kWh Conversion
26 Benchmark COS (cents) 2.958 2.958
27 Hold Harmless (cents) (0.006) 0.000
28 Settlement Credit (cents) (0.038) (0.038)

29 LIHEAP Expansion (cents] (0.008) 0.000
30 75% of January 1, 2005 increase 0.000
31 Average Cents per kWh 2.920
32
33 Post Increase Avg Cents per kWh 3.035 3.262 3.548
34
35 Company Filed COS Rev Req 233,300 258,300 295,300
36
37 Rate Year Revenues at Current Rate 224,441 240,349 271,503
38
39 Revenue Change 8,859 17,951 Cumul 23,797 Cumul
40 Rev Chng Rev Chng
41 Percent Revenue Change 3.95%(a) 7.47% 11.42%(b) 8.76% 20.18%(c)
42
43 Cumulative Reopener Threshold 5.70%(a) 11.26% 11.26%(b) 19.42% 19.42%(c)
44
45 Cumulative GDPIPD Threshold 15.60%(a) 22.40% 22.40%(b) 19.42% 19.42%(c)

(a) Cumulative Percentage Revenue Change is less than the
Cumulative Reopener Threshold for 2008, continued existence of savings is
demonstrated

(b) Cumulative Percentage Revenue Change is more than the
Cumulative Reopener Threshold for 2011 but less than Cumulative GDPIPD
threshold for 2011, Company must demonstrate continued shared savings,
(c) Cumulative Percentage Revenue Change is more than the
Cumulative Reopener threshold for 2016 and more Cumulative GDPIPD threshold
for 2016, shared savings excluded from Cost of Service,

Line 4 DRI estimated GDPIPD growth rate

Line 5 80% of Line 4
Line 6 Settled escalation rate for rate freeze period

Line 8 Estimated 2000 MWH per JMM-15, JJB-2a and JJB-2b adjusted for Division kWh adjustment escalated at 1%.

Line 12 Sum of annual amounts from Lines 6 and 5

Line 13 Sum of annual amounts from Line 4. For Years 2015 - 2019 equal to Cumulative reopener indexsame as Line 12

Line 17 Settled benchmark Cost of Service

Line 26 Line 17 divided by Line 8
Line 27 Line 19 divided by Line 8
Line 28 Line 20 divided by Line 8
Line 29 Line 21 divided by Line 8
Line 30 Line 22 divided by Line 8
Line 33 Line 35 divided by Line 8
Line 35 Total filed Cost of Service revenue requirement

Line 37 Rate Year kWh times then current average kWh Rate (Immediately preceeding Line31 or Line 33)

Line 41 Line 39 divided by Line 37

</TABLE>

Illustration of Limits on Company's Right to Retain
Proven Savings Share After Rate Freeze Period

[chart]

EXHIBIT 6

R.I.P.U.C. No. ____
Sheet 1
Cancelling R.I.P.U.C. No. 1116

THE NARRAGANSETT ELECTRIC COMPANY
NON-BYPASSABLE TRANSITION CHARGE ADJUSTMENT PROVISION

The Non-Bypassable Transition Charge shall collect from customers all
Contract Termination Charges billed to the Narragansett Electric Company
(the Company) by the New England Power Company or Montaup Electric Company.
The Non-Bypassable Transition Charge may be subject to adjustment each time
any Contract Termination Charge changes.

On an annual basis, the Company shall reconcile its total cost of
Contract Termination Charges against its total transition charge revenue
(appropriately adjusted to reflect the Rhode Island Gross Receipts Tax) to
determine any excess or deficiency ("Transition Charge Adjustment
Balance"). Any positive or negative balance will accrue interest calculated
at the rate in effect for customer deposits.

For purposes of the above reconciliation, total transition charge
revenues shall mean all revenue collected from customers through the
transition charges for the applicable reconciliation period. If there is a
positive or negative balance in the then current Transition Charge
Adjustment Balance outstanding from the prior period, the balance shall be
credited against or added to the new reconciliation amount, as appropriate,
in establishing the Transition Charge Adjustment Balance for the new
reconciliation period. The Company shall annually determine the Transition
Charge Adjustment Balance, if any, for the prior calendar year and make a
filing with the Commission.

The transition charges for the Narragansett Zone will be fixed in
accordance with the following schedule through 2004:

Year Fixed Transition Charge
Narragansett Zone

2000 1.15
2001 1.05
2002 1.05
2003 1.00
2004 0.95

The transition charges in the Blackstone and Newport Zones will be
determined by calculating the balance of the Company's total Contract
Termination Charge expenses less the estimated transition charge revenues
collected in the Narragansett Zone and dividing the balance by the
estimated kilowatt-hour deliveries in the Blackstone and Newport Zones. The
resulting transition charges in the Blackstone and Newport Zones shall not
exceed the amounts established for the period through 2004 as of the date
of this Settlement under FERC-approved CTC rates for Blackstone and
Newport, respectively ("Transition Charge Maximums"). Once transition
charges converge in the three zones, they will be set at the same rates,
with applicable adjustments being spread equally among the three zones.

To the extent that Contract Termination Charge expenses are less than
the total transition charge revenue collected from customers in any given
year, any such overrecoveries (less amounts applied in accordance with
Section 10 of the Stipulation and Settlement from Docket 2930) shall be
credited to customers, with interest at the customer deposit rate, in the
Blackstone and Newport Zones to lower transition charges for the following
year. Underrecoveries in any given year may be collected, with interest at
the customer deposit rate, in the following year to the extent allowed
under the Transition Charge Maximums specified above. To the extent that
any Contract Termination Charge expenses are not collected during this
period as a result of the Transition Charge Maximums in the Blackstone and
Newport Zones, any underrecoveries will be deferred with interest at the
customer deposit rate, for recovery after the Rate Freeze Period through a
methodology approved by the Commission.

Modifications to the Non-Bypassable Transition Charge shall be in
accordance with a notice filed with the Public Utilities Commission
(Commission) setting forth the revised charge and the amount of the
increase or decrease. The notice shall further specify the effective date
of the change.

This provision is applicable to all Retail Delivery Service rates of
the Company.

Effective ___________

R.I.P.U.C. No. 1098
Sheet 1

THE NARRAGANSETT ELECTRIC COMPANY
STANDARD OFFER ADJUSTMENT PROVISION

The prices contained in the applicable rates of the Company are
subject to adjustment to reflect the power purchase costs incurred by the
Company in arranging Standard Offer and Last Resort Service, which costs
are not recovered from customers through the Standard Offer Service and
Last Resort Service rates charged to Standard Offer and Last Resort Service
customers.

On an annual basis, the Company shall reconcile its total cost of
purchased power for Standard Offer and Last Resort Service supply against
its total purchased power revenue (appropriately adjusted to reflect the
Rhode Island Gross Receipts Tax), and the excess or deficiency ("Standard
Offer/Last Resort Adjustment Balance") shall be refunded to, or collected
from, customers through the rate recovery/refund methodology approved by
the Commission at the time the Company files its annual reconciliation. Any
positive or negative balance will accrue interest calculated at the rate in
effect for customer deposits.

For purposes of the above reconciliation, total purchased power
revenues shall mean all revenue collected from Standard Offer and Last
Resort Service customers through the Standard Offer and Last Resort Service
rates for the applicable 12 month reconciliation period. If there is a
positive or negative balance in the then current Standard Offer/Last Resort
Adjustment Balance outstanding from the prior period, the balance shall be
credited against or added to the new reconciliation amount, as appropriate,
in establishing the Standard Offer/Last Resort Adjustment Balance for the
new reconciliation period.

By March 1 of each year, the Company shall determine the Standard
Offer/Last Resort Adjustment Balance for the prior calendar year and make a
filing with the Commission. The Company will propose at that time a rate
recovery/refund methodology to recover or refund the balance, as
appropriate, over the twelve month period commencing April 1. The
Commission may order the Company to collect or refund the balance over any
reasonable time period from (i) all customers, (ii) only Standard Offer
and/or Last Resort Service customers, or (iii) through any other reasonable
method.

This provision is applicable to all Retail Delivery Service rates of
the Company.

Effective: June 1, 1998

R.I.P.U.C. NO. 887
SHEET 1
CANCELING R.I.P.U.C. NO. 881

THE NARRAGANSETT ELECTRIC COMPANY
CONSERVATION AND LOAD MANAGEMENT
ADJUSTMENT PROVISION

The prices contained in the applicable rates of the Company are
subject to adjustment to reflect conservation and load management
activities undertaken by the Company. Such activities shall be reviewed and
approved annually by the Public Utilities Commission.

4. The Conservation and Load Management Adjustment for the Company
shall be annually determined as follows:

a) On or before October 1, of each calendar year, the Company
shall file a notice with the Public Utilities Commission
describing its proposed conservation and load management
activities for the following calendar year.

b) The Commission shall have authority to review and approve,
with or without modifications, the Company's proposed
conservation and load management activities and establishing
the amount that the Company shall be authorized to collect
through rates to reflect these activities.

c) The amount of the Conservation and Load Management
Adjustment for the following calendar year shall be an
amount, computed to the nearest thousandth of a cent (
appropriately adjusted to reflect the Rhode Island Gross
Earnings Tax), equal to the amount approved by the Public
Utilities Commission pursuant to paragraph 1(b) above
divided by estimated total kilowatthour sales for the
following calendar year.

2. The Conservation and Load Management Adjustment as determined in
paragraph 1 above shall become effective with respect to bills for
meter readings on and after January 1 of the following calendar
year and will apply to all rates of the Company.

3. If conditions experienced or reasonably anticipated during a
calendar year when a Conservation and Load Management Adjustment
factor is in effect indicate that the total amount to be collected
by the Company during the calendar year will vary by ten percent or
more above or below the amount the Public Utilities Commission has
authorized to be collected during the calendar year, the Company
may apply to the Public Utilities Commission for approval and
authorization of an appropriate interim increase or decrease in the
Conservation and Load Management Adjustment Factor to be applicable
during the remainder of said calendar year.

4. Any differential between the actual and authorized amounts
collected and/or conservation funds expended pursuant to this
Conservation and Load Management Adjustment Provision during a
calendar year shall, with interest, be added to or subtracted from
the amount to be collected during the following calendar year. If
actual amounts are not available for any period they shall be
estimated for purposes of the above calculation and adjusted the
following year based on actual data.

EFFECTIVE: JANUARY 1, 1990

R.I.P.U.C. No.
Sheet 1
Cancelling R.I.P.U.C. No. 1054

THE NARRAGANSETT ELECTRIC COMPANY
TRANSMISSION SERVICE COST ADJUSTMENT PROVISION

The Transmission Service Cost Adjustment (TCA) shall collect from
customers transmission costs billed to The Narragansett Electric Company
(Narragansett or the Company) by entities such as the New England Power
Company, by any other transmission provider, and by regional transmission
entities such as the New England Power Pool, a regional transmission group,
an independent system operator or any other entity that is authorized to
bill Narragansett Electric directly for transmission services.

On the Effective Date of this adjustment provision, the TCA shall be
separately determined for the Customers in the Narragansett, Blackstone and
Newport zones to reflect the transmission costs of those companies prior to
the Effective Date as determined by a filing made by the Companies at least
30 days prior to the Effective Date.

Effective on January 1, 2001, the transmission service cost adjustment
shall be a uniform cents per kilowatthour factor applicable to all
kilowatthours delivered by the Company. The factor shall be established
annually based on a forecast of transmission costs, taking into account
revenues that will be received from base rate transmission charges, and
shall include a full reconciliation and adjustment for any over- or
under-recoveries of transmission costs incurred during the prior year. The
Company may file to change the factor adjustment at any time should
significant over- or under-recoveries occur. The reconciliation shall
calculate all revenues received by the Company through the base rate
transmission charges and this TCA, compare these revenues to all
transmission costs incurred during the corresponding year, and pass through
the resulting credit or charge, as appropriate, on a uniform per kWh basis,
as provided above.

Modifications to the Transmission Service Cost Adjustment Factor shall
be in accordance with a notice filed with the Public Utilities Commission
(the Commission) setting forth the amount of the revised factor and the
amount of the increase or decrease. The notice shall further specify the
effective date of such charges.

Effective April 1, 2000

Exhibit 7
Page 1 of 9

THE NARRAGANSETT ELECTRIC COMPANY
PERFORMANCE STANDARDS
UNDER RETAIL ACCESS TARIFFS

The Narragansett Electric Company ("Narragansett Electric" or the
"Company") shall establish the performance standards for reliability and
service that are set forth in this document. The standards are designed as
a penalty-only approach, under which the Company would be penalized if its
performance did not meet the standards, measured on a cumulative basis. The
Company receives no reward for performance which exceeds the standard.
However, positive performance in one category can be used to offset
penalties in other categories in any given year, except that offsets earned
for the two Customer Service standards can only be used in the year earned
to offset any other standard, and offsets earned in the four Reliability
standards can either be used in the year earned or in the following year.
If there are negative balances or penalties reflected in the cumulative
balance in the year following the end of the rate freeze agreed to in this
settlement, the entire balance shall be credited to customers. The manner
in which the penalty is credited to customers will be determined by the
Commission at that time.

The maximum penalty authorized under the standards set forth below
is $2.4 million per year. The Performance Standards set forth below shall
remain in effect from the effective date of the settlement through the
effective date of the Company's next base rate case provided, however,
either the Division or the Company may request modification or termination
of this plan after December 31, 2004 otherwise, the plan will remain until
it is modified by the Commission.

NOTE: When interpreting the performance standards that follow, please note
that pages 6 through 9 of this Exhibit contain definitions of terms used in
the standards.

EXHIBIT 7
Page 2 of 9

FREQUENCY OF INTERRUPTIONS PER CUSTOMER SERVED
<TABLE>
<CAPTION>

Frequency- Frequency-
Year Coastal* Capital*
---- --------- ----------
1999 1.34 0.99
1998 1.05 0.80
1997 1.17 0.81
1996 0.99 1.05
1995 1.59 1.50
1994 1.39 1.16
1993 0.93 1.05

Mean 1.21 1.05
Standard Deviation 0.22 0.22

PERFORMANCE STANDARD - Frequency of Interruptions:

Frequency- Frequency-
Coastal (Penalty)/ Capital (Penalty)/
Target Offset Target Offset
------------ -------------- ------------ ----------
<S> <C> <C> <C> <C>
More than 1.65 ($500,000) More than 1.49 ($500,000)
1.44-1.65 linear interpolation 1.28-1.49 linear interpolation
0.99-1.43 $ 0 0.83-1.27 $ 0
0.77-0.98 linear interpolation 0.61-0.82 linear interpolation
Less than 0.77 $375,000 Less than 0.61 $375,000

</TABLE>

*The calculations are based on data for the two proposed operating areas of
the combined companies - Coastal and Capital. Interruptions from
"extraordinary events" are excluded, as described in the attached criteria.

Frequency per Customer Served = Number of Customers Interrupted
-------------------------------
Number of Customers Served

EXHIBIT 7
Page 3 of 9

DURATION OF INTERRUPTIONS PER CUSTOMER SERVED

Duration- Duration-
Year Coastal* Capital*
- ------------------------------------------------------ ---------
1999 100.0 57.9
1998 54.4 32.5
1997 67.0 56.6
1996 56.1 75.3
1995 76.6 70.9
1994 56.9 55.5
1993 63.2 54.0

Mean 67.7 57.5
Standard Deviation 15.0 12.8

PERFORMANCE STANDARD - Duration of Interruptions:

Duration- Duration-
Coastal (Penalty)/ Capital (Penalty)/
Target Offset Target Offset
---------- -------------- ---------------- ----------
<S> <C> <C> <C> <C>
More than 97.7 ($500,000) More than 83.1 ($500,000)
82.8-97.7 linear interpolation 70.4-83.1 linear interpolation
52.7-82.7 $ 0 44.7-70.3 $ 0
37.7-52.6 linear interpolation 31.9-44.6 linear interpolation
Less than 37.7 $375,000 Less than 31.9 $375,000
</TABLE>

Duration per Customer Served (minutes) = Customer Minutes Interrupted
----------------------------
Number of Customers Served

EXHIBIT 7
Page 4 of 9

CUSTOMER CONTACT

Year % Satisfied*
- ------------------------------------------------------------------------
1999 82.1%
1998 77.8%
1997 79.5%

Mean 79.8%
Standard Deviation 1.8%

PERFORMANCE STANDARD - Customer Contact:

% Satisfied (Penalty)/
Target Offset
------------ ------------
Less than 76.2% ($200,000)
76.2-77.9 linear interpolation
78.0-81.6 $ 0
81.7-83.4 linear interpolation
More than 83.4% $150,000

*The calculations are based on responses from customers of Narragansett
Electric Company, based on surveys performed by an independent third party
consultant. A sample of customers who have contacted the call center are
surveyed in order to determine their level of satisfaction with their
contact. Eight types of transactions are included in the survey, and the
overall results are weighed based on the number of these transactions
actually performed at the call center during the year.

The percent satisfied represents the responses in the top two categories of
customer contact satisfaction under a seven point scale, where 1=extremely
dissatisfied and 7=extremely satisfied.

EXHIBIT 7
Page 5 of 9

TELEPHONE CALLS ANSWERED WITHIN 20 SECONDS

Percent of
Calls Answered
Year Within 20 Secs*
- ---------------------------------------------------------------------------
1999 76.9%
1998 80.9%
1997 76.7%
1996 70.2%

Mean 76.2%
Standard Deviation 3.8%

PERFORMANCE STANDARD - Telephone Calls Answered within 20 Seconds:

% Calls Answ
Within 20 Secs (Penalty)/
Target Offset
----------------- -----------
Less than 68.6% ($200,000)
68.6-72.3 linear interpolation
72.4-80.0 $ 0
80.1-83.8 linear interpolation
More than 83.8% $150,000

*The calculations are based on data for Narragansett Electric Company's
Providence call center. Eastern Utilities Associates cannot separate calls
between Massachusetts and Rhode Island.

<S> <C> <C>
Percent of Calls Answered Within 20 Secs = Total Calls Answered Within 20 Seconds
--------------------------------------
Total Calls Answered

</TABLE>

EXHIBIT 7
Page 6 of 9

DEFINITIONS OF
PERFORMANCE STANDARD
MEASUREMENTS

INTERRUPTION EVENT

The loss of service to more than one (1) customer for more than one (1)
minute.

INTERRUPTION DURATION

The period of time, measured in minutes, from the initial notification of
the interruption event to the time when service has been restored to the
customers.

NUMBER OF CUSTOMERS SERVED

The number of customers taking electric service within the defined
reporting service area on the last day of the reporting period.

NUMBER OF CUSTOMERS INTERRUPTED

The sum of the customers losing electric service for any defined grouping
of interruption events during the reporting period.

CUSTOMER MINUTES OF INTERRUPTION

The product of the number of customers interrupted and the interruption
duration for any interruption event. Also, the sum of those products for
any defined groupings of interruption events.

EXTRAORDINARY EVENTS

A particular interruption event will be considered extraordinary, and will
not count towards the Reliability Performance Standards, if it meets one of
the following criteria:

(1) It was the result of a major weather event which causes more than
10% of a district or total company customers to be without service
at a given time.

EXHIBIT 7
Page 7 of 9

(2) It was due to the failure of other companies' supply or
transmission to Narragansett Electric customers and restoration of
service was beyond the reasonable control of the Company and its
employees.

(3) It occurred because of an extraordinary circumstance, including,
without limitation, a major disaster, earthquake, wild fire, flood,
terrorism, or any other event beyond the reasonable control of the
Company.

LINEAR INTERPOLATION

1) The actual performance or penalty each year will be calculated and the
result will be scaled or interpolated linearly between the relevant two
points of the results range and the relevant two points on the dollar
range.

2) The method of determining the actual penalty, or offset, of each
performance standard is determined by multiplying the value of the penalty,
or offset, by the absolute value of the actual performance indicator minus
the value of the first standard deviation from the mean of that indicator,
divided by the value of the second standard deviation of the mean of that
indicator minus the value of the first standard deviation from the mean of
that indicator.

<TABLE>

<S> <C>
$ Penalty or Offset = Penalty or Offset $ Value x Actual - 1st standard deviation
------------------------------------------
2nd standard deviation - 1st standard deviation

</TABLE>

CUSTOMER CONTACT

The calculations are based on responses from customers of Narragansett
Electric Company, based on surveys performed by an independent third party
consultant. A sample of customers who have contacted the call center are
surveyed in order to determine their level of satisfaction with their
contact. The company will maintain the same levels of statistical precision
of the results as in prior surveys. Eight types of transactions are
included in the survey, and the overall results are weighed based on the
number of these transactions actually performed at the call center during
the year. The eight types of transactions are power Interruptions, meter
on, meter off, meter exchange, collection, payment plan, meter reread, and
meter test.

The percent satisfied represents the responses in the top two categories of
customer contact satisfaction under a seven-point scale, where 1=extremely
dissatisfied and 7=extremely satisfied.

TELEPHONE CALLS ANSWERED WITHIN 20 SECONDS

The percent of calls answered within 20 seconds is calculated by dividing
the number of calls answered by a customer service representative within 20
seconds by the total number of calls answered by a customer service
representative during the year. A call is considered answered when it
reaches a customer service representative; abandoned calls are not
considered. All calls that are answered by a customer service
representative are included in the measurement of percentage answered;
there are no exclusions. The time to answer is measured once the customer
selects the option to speak with a customer service representative and thus
leaves the recordings in the Voice Response Unit.

ADDITIONAL REPORTING CRITERIA

1. Each quarter, the company will file a report of 5% of all circuits
designated as worst performing on the basis of customer frequency.

Included in the report will be:

1. The circuit id and location
2. The number of customers served
3. The towns served
4. The number of events
5. The average duration
6. The total customer minutes
7. A discussion of the cause or causes of events
8. A discussion of the action plan for improvement including timing

2. Narragansett will track and report monthly the number of calls it
receives in the category of Trouble, Non-Outage. This includes inquiries
about dim lights, low voltage, half-power, flickering lights, reduced TV
picture size, high voltage, frequently burned out bulbs, motor running
problems, damaged appliances and equipment, computer operation problems and
other non-Interruptions related inquiries.

3. In addition, Narragansett will report its annual meter reading
performance as an average of monthly percentage of meters read.

EXHIBIT 8

R.I.P.U.C. No. ____
Sheet 112
Cancelling R.I.P.U.C. No. 1056

THE NARRAGANSETT ELECTRIC COMPANY

TERMS AND CONDITIONS

The following Terms and Conditions where not inconsistent with the rates
are a part of all rates. The provisions of these Terms and Conditions apply
to all persons, partnerships, corporations or others (the Customer) who
obtain local distribution service from The Narragansett Electric Company
(the Company) and to companies that are non-regulated power producers, as
defined in Rhode Island General Laws. All policies, standards,
specifications, and documents referred to herein have been filed with the
Rhode Island Public Utilities Commission (Commission) and Division, and
such documents and any revisions have been filed at least 30 days before
becoming effective. Compliance by the Customer and non-regulated power
producer is a condition precedent to the initial and continuing delivery of
electricity by the Company:

Service Connection

1. The Customer shall wire to the point designated by the Company, at which
point the Company will connect its facilities. In addition, the Customer's
facilities shall comply with any reasonable construction and equipment
standards required by the Company for safe, reliable, and cost efficient
service.

Application for Service

2. Application for new service or alteration to an existing service should
be made as far in advance as possible to assure time for engineering,
ordering of material, and construction. Upon the Company's reasonable
request, the Customer shall provide to the Company all data and plans
reasonably needed to process this application.

Line Extensions [Overhead (OH) & Underground (UG)]

3. The Company shall construct or install overhead or underground
distribution facilities or other equipment determined by the Company to be
appropriate under the following policies: Line Extension Policy for
Residential Developments, Line Extension Policy for Individual Residential
Customers, and Line Extension and Construction Advance Policy for
Commercial, Industrial and Non-residential Customers. Whenever it is
necessary to provide service and a Customer requests the Company to extend
or install poles, distribution lines or other service equipment to the
Customer's home, premises or facility in order to supply service, the
Company will furnish the necessary poles, wires, or equipment in accordance
with the Company's "Line Extension and Construction Advance Policies" on
file with the Commission. Except as provided in the "Policies", all such
equipment, poles, and wires shall remain the property of the Company and be
maintained by it in accordance with the "Policies". To the extent that any
Company property needs to be located on private property, the Company will
require the Customer to furnish a permanent easement.

Attachments

4. Any individual or organization who requests an attachment to
distribution facilities, utility poles, or along any span between such
poles, shall comply with the Company's specifications and policies
governing the type of construction, metering, attachment fees, easements,
permissions and electrical inspections required.

Outside Basic Local Distribution Services

5. Customers requesting the Company to arrange for Customer facility
outages or additional maintenance or construction not normally part of
basic local distribution service will be notified in a reasonable timely
manner by the Company that the customer shall be required to pay these the
Company's costs of reasonably meeting the request.

Acquisition of Necessary Permits

6. The Company shall make, or cause to be made, application for any
necessary street permits, and shall not be required to supply service until
a reasonable time after such permits are granted. The Customer shall obtain
or cause to be obtained all permits or certificates, except street permits,
necessary to give the Company or its agents access to the Customer's
equipment and to enable its conductors to be connected with the Customer's
equipment.

Service to "Out-Building"

7. The Company shall not be required to install service or meter for a
garage, barn or other out- building, so located that it may be supplied
with electricity through a service and meter in the main building.

Customer Furnished Equipment

8. The Customer shall furnish and install upon its premises such service
conductors, service equipment, including circuit breaker if used, and meter
mounting device as shall conform with specifications issued from time to
time by the Company, and the Company will seal such service equipment and
meter mounting device, and adjust, set and seal such oil circuit breaker,
and such seals shall not be broken and such adjustments or settings shall
not be changed or in any way interfered with by the Customer.

The Customer shall furnish and maintain, at no cost to the Company, the
necessary space, housing, fencing, and foundations for all equipment that
is installed on its premises in order to supply the Customer with local
distribution service, whether such equipment is furnished by the Customer
or the Company. Such space, housing, fencing, and foundations shall be in
conformity with the Company's specifications and subject to its approval.

Up-Keep of Customer Equipment

9. The Customer's wiring, piping, apparatus and equipment shall, at all
times, conform to the requirements of any legally constituted authorities
and to those of the Company, and the Customer shall keep such wiring,
piping, apparatus and equipment in proper repair.

Installation of Meters

10. Meters of either the indoor or outdoor type shall be installed by the
Company at locations to be designated by the Company. The Company may at
any time change any meter installed by it. The Company may also change the
location of any meter or change from an indoor type to an outdoor type,
provided that the cost of the change shall be borne by the Company except
when such change is pursuant to the provisions of Paragraph 11. Upon the
reading of the Company's meter all bills shall be computed. If more than
one meter is installed, unless it is installed at the Company's option, the
monthly charge for local distribution service delivered through each meter
shall be computed separately under the applicable rates.

Unauthorized and Unmetered Use

11. Whenever the Company determines that an unauthorized and unmetered use
of electricity is being made on the premises of a Customer and is causing a
loss of revenue to the Company, the Company may, at the Customer's expense,
make such changes in the location of its meters, appliance and equipment on
said premises as will, in the opinion of the Company, prevent such
unauthorized and unmetered use from being made.

Definition of Month

12. Whenever reference is made to "month" in connection with electricity
delivered or payments to be made, it shall mean the period between two
successive regular monthly meter readings or estimated meter readings, the
second of which occurs in the month to which reference is made. If the
Company is unable to read the meter when scheduled, the necessary billing
determinants may be estimated. Bills may be rendered on such estimated
basis and will be payable as so rendered. Should the Company be requested
to perform an off-cycle meter reading to facilitate a Customer request to
change their non-regulated power producer, the Company will reasonably
accommodate such a request, for which the Customer will be charged a fee
not to exceed $20.

Payment Due Date -- Interest Charge

13. All bills shall be due and payable upon receipt. Bills rendered to
customers, other than individually metered residential customers, on which
payment has not been received by the "Avoid Interest Date" as shown on the
bill, shall bear interest, at the rate of 1 1/4% per month on any unpaid
balance, including any outstanding interest charges, from the date of
receipt until the date of payment. The "Avoid Interest Date" corresponds to
the next normal bill preparation date.

Bills disputed in good faith by a Customer will not be subject to the late
payment charge until after the dispute is resolved.

Customer payment responsibilities with their non-regulated power producer
will be governed by the particular Customer/non-regulated power producer
contract. Payments made through the Company for electricity purchased from
a non-regulated power supplier will be applied first to any Narragansett
charges or arrearages.

Returned Check Fee

14. A $15.00 Fee shall be charged to the Customer for each check presented
to the Company that is not honored by the financial institution. This fee
shall be applicable only where the check has been dishonored after being
deposited for a second time.

Seasonal Customers

15. Seasonal Customers are those using local distribution services between
June lst and September 30th only, or those using local distribution
services principally between June lst and September 30th and incidentally
or intermittently during the rest of the year.

Deposit and Security

16. The Company may require a cash deposit or other collateral satisfactory
to it as security for prompt payment of the Customer's indebtedness to the
Company. The rate of interest shall be adjusted on March lst annually. The
interest rate in effect in any year shall be based on the average rate over
the prior calendar year for 10-year constant maturity Treasury Bonds as
reported by the Federal Reserve Board.

Payments for Line Extensions

17. The Company may require a Customer to pay for all or a portion of the
cost of extending or installing poles, distribution lines, or equipment to
the Customer's home, premises or facility, consistent with the terms of the
Company's "Line Extension and Construction Advance Policies" on file with
the Commission.

Determining Customer's Demand

18. The demand is the maximum rate of taking electricity. Under ordinary
load conditions it will be based upon one or more fifteen-minute peaks as
herein defined. A fifteen-minute peak is the average rate of delivery of
electricity during any fifteen-minute period as determined by any suitable
instrument chosen by the Company. In the case of extremely fluctuating
load, however, where the demand based on the average over fifteen minutes
does not fairly represent the maximum demand imposed by the Customer, the
demand will be based upon the instantaneous peak or the peak for a shorter
period than fifteen minutes. Such measurements will be made by any suitable
instrument chosen by the Company. The demand which is billed to the
Customer is determined according to the terms of the appropriate tariffs
approved by the PUC from time to time.

Customer Changing Rates

19. The Customer may change from the rate under which he is purchasing
electricity to any other rate applicable to a class of service which he is
receiving. Any change, however, shall not be retroactive, nor reduce,
eliminate or modify any contract period, provision or guarantee made in
respect to any line extension or other special condition. Nor shall such
change cause such service to be billed at any rate for a period less than
that specified in such rate except during the first year of electric
service to any Customer. A Customer having changed from one rate to another
may not again change within twelve months or within any longer contract
period specified in the rate under which he is receiving electric service.

Discontinuance of Service

20. Subject to the Rules and Regulations of the Commission, the Company
shall have the right to discontinue its service upon due notice and to
remove its property from the premises in case the Customer fails to pay any
bill due the Company for such service, or fails to perform any of its
obligations to the Company. For restoration of service after such
discontinuance, a reconnection charge of $10.00 will be made.

Right of Access

21. The Company shall have the right of access to the Customer's premises
at all reasonable times for the purpose of examining or removing the
Company's meters, and other appliances and equipment. During emergency
conditions, the Company shall have the right of access to the Customer's
premises at all hours of the day to make conditions safe and/or to restore
service.

Safeguarding Company Equipment

22. The Customer shall not permit access for any purpose whatsoever, except
by authorized employees of the Company, to the meter or other appliances
and equipment of the Company, or interfere with the same, and shall provide
for their safe keeping. In case of loss or damage of the Company's
property, the Customer shall pay to the Company the value of such property
or the cost of making good the same.

Temporary Service

23. A temporary connection is local distribution service which does not
continue for a sufficient period to yield the Company adequate revenue at
its regular local distribution service rates to justify the expenditures
necessary to provide such a connection. The Company may require a Customer
requesting a temporary connection to pay the full amount of the estimated
cost of installing and removing the requested connection, less estimated
salvage value, in advance of the installation of the connection by the
Company. In addition, the customer shall pay the applicable regular local
distribution service and, if applicable, basic or standard offer service
rates.

Limitation of Liability for Service Problems,

24. The Company shall not be liable for any damage to equipment or
facilities using electricity which damage is a result of Service Problems,
or any economic losses which are a consequence of Service Problems. For
purposes of this paragraph, the term "Service Problems" means any service
interruption, power outage, voltage or amperage, fluctuations,
discontinuance of service, reversal of its service, or irregular service
caused by accident, labor difficulties, condition of fuel supply or
equipment, federal or state agency order, failure to receive any
electricity for which the Company has contracted, or any other causes
beyond the Company's immediate control.

However, if the Company is unable for any reason to supply electricity for
a continuous period of two days or more, then upon the request of the
Customer, the Demand Charge, if any, shall be suspended for the duration of
such inability.

The Company shall not be liable for damage to the person or property of the
Customer or any other persons resulting from the use of electricity or the
presence of the Company's appliances and equipment on the Customer's
premises.

Limitation on Use of Electricity - Auxiliary & Temporary Local
Distribution Service

25. Local distribution service supplied by the Company shall not be used to
supplement or relay, or as standby or back up to any other electrical
source or service except under the provisions of the Auxiliary Service Rate
OR BACK-UP SERVICE RATE, unless the Customer shall makes such guarantees
with respect to the payment for such local distribution service as shall be
just and reasonable in each case. Where such local distribution service is
supplied, the Customer shall not operate its generation in parallel with
the Company's system without the consent of the Company, and then only
under such conditions as the Company may specify from time to time.

Company Right to Place Facilities on Customer Property

26. The Company has the right to place on a Customer's property facilities
to provide and meter electric service to the Customer.

Company Right to Request a Guarantee

27. Whenever the estimated expenditures for the services or equipment
necessary to deliver electricity to a Customer's premises shall be of such
an amount that the income to be derived therefrom at the applicable rates
will, in the opinion of the Company, be insufficient to warrant such
expenditures, the Company may require a Customer to guarantee a minimum
annual payment or commitment for a term of years, or to pay the whole or a
part of the cost of such equipment.

[Ongoing Power Service

[29] 28. Customers who have not contracted for a power supply with a
non-regulated power producer may elect service from the Company's approved
tariffs for Interim Power Service until such time as Standard Offer Service
is available, at which time Interim Power Service will not be available.]

Fluctuating Load & Harmonic Distortion

[30] 29. In certain instances, extreme fluctuating loads or harmonic
distortions which are created by a Customer's machinery or equipment may
impair service to other Customers. If the fluctuating load or harmonic
distortion causes a deterioration of the Company's service to other
customers, the Company shall specify a service arrangement that avoids the
deterioration and the Customer owning or operating the equipment that
causes the fluctuation or distortion shall pay the cost to implement the
new service arrangement together with applicable taxes.

Customer Tax Liability

[31] 30. The Company shall collect taxes imposed by governmental authorities
on services provided or products sold by the Company. It shall be the
Customer's responsibility to identify and request any exemption from the
collection of the tax by filing appropriate documentation with the Company.

Customer/Supplier Relationship

[32] 31. For electricity supplied by non-regulated power producers, the
Company is a local distribution service provider of electricity supplied by
others. When such electricity is supplied and delivered to the Company's
local distribution supply point, the Company then performs a delivery
service for the electricity. Ownership of such electricity lies with either
the non-regulated power producer or Customer, as per the specific agreement
between the Customer and the non-regulated power producer. In no case shall
the Company be liable for loss of electricity.

Customer Notice and Right to Appeal

32. Where practicable, the Company will give the Customer reasonable
notice of actions taken pursuant to these Terms & Conditions. The Customer
shall have the right to appeal, pursuant to the Division's Rules of
Practice and Procedure, all action taken by the Company hereunder.

[Switching Between Tariffs

33. A Customer taking service on a Retail Delivery Service rate may change
to another applicable Retail Delivery Service rate at any time, except that
once a customer changes to the new rate, the Customer must stay on that
rate for at least one year.

A Customer taking service on an Interim Power Service rate may change to
another applicable Interim Power Service rate at any time, except that once
a Customer changes to the new rate, the Customer must stay on that rate for
at least one year.

Customers may change from a Retail Delivery Service rate to an applicable
Interim Power Service rate at any time, subject to the limitations
contained in the Terms and Conditions for Non-Regulated Power Producers.

Prior to Standard Offer Service being applicable, Customers taking Retail
Delivery Service may switch back to an applicable Interim Power Service
rate, subject to the limitations suppliers contained in the Terms and
Conditions for Non Regulated Power Producers.]

DEFINITIONS OF ZONES

32. FOR PURPOSES OF INTERPRETING RATES, TARIFFS AND TERMS AND CONDITIONS,
THE FOLLOWING TERMS WILL HAVE THE MEANINGS AS FOLLOWS:

NARRAGANSETT ZONE IS THE CITIES AND TOWNS OF: PROVIDENCE, NORTH
PROVIDENCE, EAST PROVIDENCE, CRANSTON, JOHNSTON, SMITHFIELD, SCITUATE,
FOSTER, GLOUCESTER, WARREN, BARRINGTON, BRISTOL, TIVERTON, LITTLE
COMPTON, WARWICK, WEST WARWICK, EAST GREENWICH, COVENTRY, NORTH
KINGSTOWN, WESTERLY, RICHMOND, CHARLESTOWN, EXETER, HOPKINTON,
NARRAGANSETT, SOUTH KINGSTOWN AND WEST GREENWICH.

BLACKSTONE VALLEY ZONE IS THE CITIES AND TOWNS OF: PAWTUCKET, CENTRAL
FALLS, CUMBERLAND, LINCOLN, WOONSOCKET, NORTH SMITHFIELD, AND
BURRILLVILLE

NEWPORT ZONE IS THE CITIES AND TOWNS OF: NEWPORT, MIDDLETOWN,
PORTSMOUTH, AND JAMESTOWN.

EXHIBIT 9

LIST OF MANUFACTURED GAS PLANT LOCATIONS

Washington Street, Bristol

Thames Street, Bristol

Main Street, Warren

Canal Street, Westerly

Industrial Drive, Westerly

Tidewater Street, Pawtucket

Exchange Street, Pawtucket

High Street, Central Falls

Hamlet Ave, Woonsocket

Pond Street, Woonsocket

Cumberland (remote disposal location)

Lawn Street, Attleboro, Mass.

Mendon Road, Attleboro, Mass.